Edition Thirty Nine - June 2015

The Stock to Own if US Oil Production Stays Stronger for Longer

What if Oil Is the Best Investment of 2015?

U.S. Oil Market Update- Blame Canada!

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Issue 39 June 2015

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Adam Marmaras

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Hello and welcome to the 39th edition of the OilVoice magazine. This month we have articles from Keith Schaefer, Kurt Cobb and Malcolm Wilson. I'm sure you'll enjoy reading them.

Summer is around the corner, and it is traditionally a time for the industry to slow down. There are no major exhibitions or conferences, and "out of office" replies are the norm. Our team can struggle to fill the site with relevant news as the PR machines grind to a halt too. But with the oil price still in limbo, I have no doubt that our trusty team of bloggers will keep us entertained and informed. So keep checking OilVoice daily - I'm sure you do anyway...

Enjoy the magazine!

Adam Marmaras

Managing Director OilVoice

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Table of Contents

Conformance control for clever clogs by Stephen A. Brown

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The Market has Waited 3 Years to See This Drilled by Keith Schaefer

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Dj vu for the Falkland Islands / Islas Malvinas by Tom Palmer

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Are oil and gas companies across the world 'complacent' on financial risk of suppliers? by Malcolm Wilson

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What if Oil Is the Best Investment of 2015? by Keith Schaefer

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U.S. Oil Market Update- Blame Canada! by Nathan Weiss and Keith Schaefer

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Why We Have an Oversupply of Almost Everything (Oil, labor, capital, etc.) by Gail Tverberg

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Is the slowdown in productivity growth a result of energy costs? by Kurt Cobb

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Who's who in steam by Stephen A. Brown

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The Stock to Own if US Oil Production Stays Stronger for Longer by Keith Schaefer

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Conformance control for clever clogs Written by Stephen A. Brown from The Steam Oil Production Company Ltd

What do I mean by conformance control, well it's just a fancy engineering term for producing, or injecting, more of what you want and less of what you don't want. In the oilfield we use the word to indicate that we have done something to the downhole configuration to direct fluids where we want them to go.

We have done it forever. Way back in the mists of time when I was working offshore on Forties, if a well's water cut rose too high we would run a bridge plug into the well to shut off the water producing zone and let the oil flow freely again. In a trice a well that was dead could be resurrected and flow say 15,000 bbls per day again - I'm looking at you FB15 (egg box 5 well 6) in the spring of '87.

That was one of the great advantages of having vertical or near-vertical wells in high quality homogenous reservoirs. The oil came in at the bottom of the wells and a simple bridge plug astutely placed could make a dramatic difference. In heterogenous reservoirs we would have had to use casing patches or something much more complex, or just have to put up with processing the water and gas we didn't really want.

Horizontal wells have changed all that. Now, in a very homogenous reservoir we would expect water or gas to start to cone into the heel of the well, as that is where the pressure sink is deepest; a bridge plug would be of no use to us there, it would block off production from the whole well. So interventions can be difficult and really something that needs to be planned in to the well design upfront.

For steam floods, the key to success is stopping steam when it breaks through, so that the whole reservoir, not just a small part of it, can be swept by the steam. For steam floods using horizontal wells, stopping steam breakthrough is even more important as each horizontal well is doing the work of maybe ten to fifteen vertical wells. When steam hits the producer we want to shut off that part of the well and force the steam front to sweep the rest of the reservoir. For Pilot, our initial plan was to run a distributed temperature monitoring system in the well and place a series of

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sliding sleeves in the completion so that we could shut off production from the hottest parts of the well.

The novel Autonomous Inflow Control Valve (AICV) from Inflow Control of Norway; and courtesy of Inflow Control AS

Then we found this technology - an autonomous inflow control valve, the AICV. They are made by an innovative young company from Norway called Inflow Control. Halliburton and Baker Hughes make similar devices and Schlumberger have something akin to it in the works, but as I have studied the AICV I'll try to explain how that particular device works.

In each and every joint of sand screen installed in the well you install one of these valves. The sand screens need to be fitted with an internal blank pipe so that all the fluids that come through the sand screens are diverted through this device before entering the production tubing.

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An AICV inflow control device installed in a pre-assembled completion and courtesy of Inflow Control AS

So how does the valve work?

Well, there are two flow paths through the valve, one which is always open, let's call it the pilot flow path (just like the pilot flame on your gas boiler) and another which is either closed or open. The pilot flow pathway is designed with two flow restrictions built in; one which operates in the laminar flow regime and one which triggers turbulent flow, something like an orifice plate. High viscosity fluids struggle through the laminar restrictor so midway through the pilot flow path the pressure is low. Low viscosity fluids fly through the laminar restrictor, but suffer a big pressure drop as they pass through the turbulent restrictor, so, if the fluids have a low viscosity, midway through the pilot flow pathway the pressure is high.

AICV in the open position; and courtesy of Inflow Control AS

Those differences in pressure are harnessed to keep the main flow pathway open when the fluid has a high viscosity. The thickest blue arrow shows the inlet of the main flow to the valve, and the two horizontal arrows show the outlet of the main flow into the base pipe. The thin blue vertical arrow represents the outlet of the pilot flow. The yellow piston is actuated by the pressure midway through the the pilot flow path. When the fluid is viscous, the pressure below the yellow piston is low and the valve stays open.

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AICV in the closed position; and courtesy of Inflow Control AS

When the fluid is less viscous the pressure beneath the yellow piston is relatively high, the yellow piston is forced upwards and, in doing so, shuts off the main flow pathway. When the valve is fully open only 1% to 5% of the fluid passes through the pilot flow path. So when the valve closes, it can autonomously shut off over 95% of the flow from that joint of pipe.

Just one moving part, no electronics and no attempt to send signals back up the wellbore; so simple, so elegant, so clever, and potentially a game changing technology with lots of applications.

Inflow Control is testing a specially designed version of the AICV which can tolerate temperatures as high as 310C in a SAGD production well in Canada this summer. We will be waiting to hear how the trials go and we hope the product lives up to their (and our) expectations and that it works as well in practice as it does in this video.

and courtesy of Inflow Control AS

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The Market has Waited 3 Years to See This Drilled

Written by Keith Schaefer from Oil & Gas Investments Bulletin

The Shale Revolution is strictly a North American game. Before the Great Commodity Collapse of 2014, it really never found its footing anywhere else in the world.

Of all the plays I looked and of the few I covered, only one showed any real promisethe Vaca Muerta oil play in western Argentina.

I'm now making that TWO playsafter researching the Beetaloo Basin in north-central Australia.

Northern Australia has just gone through the most focused Liquid Natural Gas (LNG) development the world has ever experienced, and is set to become the world's largest exporter of LNG in the next two yearsfrom basically zero.

As an example, France's Total and Japan's INPEX are investing $34 Billion in LNG in Darwin for two LNG facilities. The feedstock for those facilities is 890 km offshore.

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So I found it really interesting that INPEX just picked up 2.4 million acres in the Beetaloo. They must commit to a work program, and INPEX hasn't said what it is yet. But the point is there is now some well-funded, large international companies about to spend millions in some promising virgin geology.

All the infrastructure to process trillions of feet of cubic gas is already built; and a gas pipeline already goes through the Beetaloo up to Darwin. That is key. Oil infrastructure however would definitely cost more.

Natural gas prices in Asialike the JKM benchmarkhave come down a lot, but the Aussie LNG industry says their LNG is economic at $40 oil. LNG is generally priced about 13-15% of Brent oil.

And I absolutely love that I get to watch this play unfold during the commodity collapsebecause it means I get to watch for free. There is no speculative premium in any play or stock, and the fundamentals here are very intriguing.

The Beetaloo reminds me a lot of the Permian Basin in west Texasthe granddaddy of oil plays in North America.

Any new horizontal play in today's world must have stackedpay formations. What stacked paymeans is that there are multiple productive oil and gas formations on the same piece of land. One well bore can pass through several formations.

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It is common sense really. Once you spend the money to build the roads, lay the pipelines and establish the drilling site to develop one productive zone, you can re-use all of that again to develop the other zones.

That means cost per barrel of production goes way down, and profits go way up.

It is that stacked formations that exist in the Permian Basin in Texas that made it the hottest oil and gas area in the United States. During the height of the boom last year, there were more rigs drilling in the Permian than anywhere else on the planet.

Like the Permian, the Beetaloo has several different formations with potential.

Having stacked pay doesn't mean every formation will flow hydrocarbons, but it does offer the potential that oil and gas producers are interested in.

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Given the multiple formations, the amount of oil and gas in the ground in the Beetaloo is big-Really Big. With today's energy pricing, you need Really Big to create economies of scale to make money.

According to the work done by reservoir engineers at RPS in 2013, the best case hydrocarbon resource in the Beetaloo Basin is 21.3 billion barrels of oil and 162 trillion cubic feet of natural gas.

The Beetaloo has pay zones for both shallower oil and deeper gas:

Shale oil - Upper Kyalla, Lower Kyalla and Middle Velkerri Shale gas - Lower Kyalla and Middle Velkerri Tight gas - Moroak and Bessie Creek

The Beetaloo has been drilled vertically beforein the 1980s by Rio Tintoand RPS used that core data (12 wells) to come up with that estimate.

Of course, there are still some Big Challenges operating in Northern Australia. This is a remote frontier.

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One such challenge will be the weather. In this region you have 6 dry months where conditions are excellent (May to October) and 6 wet months where you aren't going to be able to get anything done (November to April). When the calendar hits October it will be crucial to get equipment out of the region or risk paying for it to sit idle for the rainy months.

Another challenge is a lack of infrastructure. There is a pipeline there, but supporting a drilling and fracking operation 600 km away from any mechanical centre is difficult. In Alberta or Texas, a missing or broken part is usually replaced the same or next day.

Rig repairs could realistically be a couple weeks in Northern Australia.

Developing the horizontal/unconventional part of the play is more expensive but less risky-because it doesn't carry the exploration risk that a conventional drilling target does. When you drill a conventional target (I'm talking about the oil pools everybody searched for only 10-15 years ago ;-)), there is always a chance that the hydrocarbons have migrated out of the structure.

With an unconventional play companies know that the resource is there, the only question is whether they can get it out profitably.

Down the road, companies operating in the Beetaloo might get a second life by going after the conventional opportunities. This play has the ingredients that could turn it into a major international horizontal play.

It's a huge play, and not a place you would expect to find a small company highly levered to succeed there. But there is one, and they have arranged all the pieces of the puzzle so that their Big Partners are paying ALL the freight. I like that. Drilling starts next month; I like that even more. I'll get into that in Part Two of my look at the Beetaloo Basin.

View more quality content from Oil & Gas Investments Bulletin

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Dj vu for the Falkland Islands / Islas Malvinas

Written by Tom Palmer from Palantir

The Falkland Islands or Islas Malvinas is a favourite destination for wildlife fans, hosting thousands of Penguins, Elephant Seals, Sea Lions, and 65% of the world's black-browed albatross bird population. There are two types of sea lion in the Falkland Islands since 2012, the only common connection is they both share the waters around the islands.

The first sea lion is a sea mammal characterized by external ear flaps, long fore flippers, the ability to walk on all fours, and short, thick hair. The second is a larger oil field in the North Falklands Basin, whose first phase of development is expected to commercialise 160mmbbls of oil at an initial cost of $2 billion. The Sea Lion field is a good barometer for the development of oil and gas in the Falkland Islands, but also a sign of the current times, as its development has been split into two phases to reduce cost. Nether the less, it remains a capital intensive project that will be subject to increased scrutiny in these current times.

The low oil price in 1998 of around $10 a barrel put the exploitation of oil in the Falklands Islands on hold. Now history is repeating, but this time for a different set of companies operating in the islands. Oil and gas companies need to maintain their cash flows during times of low oil and gas prices, thereby delaying or putting on hold capital investment decisions. The oil price did not encourage the development of oil and gas in the Falklands after the first phase of explorative drilling, and it appears that once again the oil price has come back to hamper developments before they have begun.

History Oil was first discovered in 1970s via academic studies from three boreholes. Yet as a result of the Falklands War and political fallout, activities ceased. It wasn't until 1996 that the first licences were awarded to 14 companies, in which six wells were drilled in 1998 by Hess, Lasmo (Bought by ENI), Shell and Lundin. However, things took a turn for the worse when the 1998 oil price dropped to around $10 a barrel with continued political fallout and the collapse of the 1995 accord.

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Since 1998, additional licences have been awarded and relinquished, multiple new 3D surveys conducted and farm in and farm outs completed. This all took place during a period of increasing oil prices and greater certainty of returns from the Falklands for these companies. However, it wasn't until 2010 to 2012 that activity in the area sparked to life again as oil prices rose to $70 a barrel and beyond. The current operators and their activities in the Falklands Islands are shown in the diagram below.

Figure 1 - Falkland Islands licences 2012 Source: Daily Telegraph

During two drilling campaigns from 2010 to 2012, a total of 21 wells were drilled, with four being dry holes and the rest being oil (northern basis predominantly) or gas (south basins). This brought about the prospect of turning Falklands into an important hydrocarbon producer.

The Falkland Island's existing fiscal regime was introduced in 1996 for the competitive licence rounds, but is also applicable for the open door licences after 2001 and has been stable partly due to the infancy of the oil and gas industry there. The fiscal regime is relatively simple with the following key terms:

Royalty of 9% Acreage rental fees ($375,000 per km2 per annum during development) Corporate Tax (21% on first 1million profits, 26% afterwards)

Utilising the Palantir Regime Library a sample project in the Falklands Islands would result in a government take of around 35%. Using this same sample project and assumption, Greenland, another prospective area would have an equivalent

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government take of 68%, while a non-Petroleum Revenue Tax field in the UK would be around 63%. The Falkland Islands is much more comparable to the 35% government take in Israel, an area being developed by an existing Falkland Islands operator that is also seeking to expand.

Who is there now?

With the farm in and outs that have taken place recently, the operators and partners have continually changed.

In 2013, Falklands Oil and Gas paid 61million to purchase Desire Petroleum increasing its activity in the Falkland Islands further.

Even the licence status on the Falkland Islands Government website (as shown below) is out of date since January this year. In April, Argos Resources agreed to farm out of PL001, with Noble Energy taking a 75% interest and Edison taking a 25% interest, although Argos Resources will retain an overriding royalty interest of 5% if hydrocarbons are discovered.

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Figure 2 - Falkland Islands Production Licences. Source: Falkland Islands Government

All about cash flow?

The drop in the oil price from the relative highs of $100 a barrel has meant companies have had to change their investment strategy, to ensure they can maintain their cash flow. Investments in conventional oil and gas assets occur over a long period of around 20 years and the oil price may recover to recent highs during this period. However, it doesn't mean the company will still go ahead with the investment as they will need to manage their short term cash flows.

With either lower revenues from existing assets, companies will instead focus on being able to meet their financial requirements, having a working capital that allows them to pay creditors and avoid bankruptcy. Future investments will get delayed, sold or farmed out to meet their current concerns.

Yet, the continued political tension and legal action in the Falkland Islands will limit the candidates companies available for sale or farm out options and potentially hamper the ability to have funds for proposed development projects. Only companies that have a strong working capital are likely to be able to go anti-cyclical to the market and continue with large capital investments. If so, they may be able to benefit from a potential upside in future prices if current production begins to drop off and investments in exploration and development are postponed.

Low oil prices also impact the hitting prices of some companies due to depressed revenues on future production. This makes them a target for acquisition, or those companies again with required cash flows, potentially impinging on future potential spending plans as portfolios become merged.

The main players

In order to understand the impact of lower prices on plans in the Falkland Islands, the majority of companies in the region are small operators. However, more medium sized players appear to be entering the market to support the financial requirements necessary for further drilling and development.

Rockhopper operates in the Mediterranean where it has a working interest in a gas

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producing asset with ENI when it purchased AIM listed Mediterranean Oil & Gas in 2014. In the Falkland Islands, Premier Oil has interests in 5 different licences in the region. The most famous of these is the Sea Lion Field (PL032), which it choose to farm out 60% to Premier Oil. Rockhopper had an exploration carry as part of the transaction and is believed to benefit from a development carry through a potential phased development for the field and has been able to recently defer its tax liability from the transfer. This is good news for Rockhopper, but will mean that the capital investment required for development will be in the hands of Premier Oil.

Premier Oil chose to farm into 6 different licences, becoming the operator for 4 of the fields. Premier Oil, Falkland Oil & Gas and Rockhopper announced an oil discovery in the Falklands in April this year at PL004b. Despite the increased success for Premier and Rockhopper, their finds will now require the capital to invest in their Sea Lion development. The difficulty for Premier Oil is that it has a large interest in UK and Norway which are two very high cost areas. The low oil price will make some of these fields loss making. It is likely that Premier Oil will seek to limit capital expenditure putting Falkland Island activities on hold.

Recent estimates valued Premier Oil at below $13 per barrel of 2P Oil Reserves and has decreased further since, making them a prime target for a potential takeover target themselves. In 2014, Premier Oil decided to scale back the plans with its Sea Lion field, splitting it into two phases with a tension leg platform and a leased FPSO to lower capital costs. This was also intended to remove the need for a farm-out of the licence to help pay for the development. Since this announcement, prices have decreased further and plans will either have to be put on hold or the option for farm-out will need to be revisited.

Falklands Oil & Gas (FOGL) as the name suggests operates exclusively within the Falkland's Islands, but having a working interest in 19 fields in both the North Falkland and South Falkland basins. FOGL, Premier Oil and Rockhopper, as previously mentioned, made a larger than expected oil and gas discovery in the PL004b 'Zebedee' licence, which the sea lion field straddles. This is positive news within the region, creating the opportunity to develop hub facilities within the sea lion field area/fields to share and potentially reduce costs if possible for the benefit of both licences and potentially more in the North Falklands Basin.

Noble Energy, unlike the other companies in the region, entered the sector recently with its acquisition of Argos Resources' licence in partnership with Edison. As such,

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Noble with Edison have chosen to delay drilling but buy into a new licence in the area. They may have realised that it may be a better time to buy into fields when prices are low, rather than spend capex on drilling and development. Noble Energy, suffering from low oil prices, have recently been cutting capex, within its Deepwater GOM and Marcellus Shale projects. Likewise, Noble have large capital investments in the Mediterranean assets with the Leviathan gas field.

Is the lower oil price all bad?

With low oil prices comes reduced exploration/development activity, but it also causes downward pressure on prices globally. In the oil sector companies that have no, or limited operating assets, have some positives as day rates for drillships and jackups have been coming down. That being said, as a small company it is often easier to seek credit for exploration activities when they have a cash flow from operating assets, so it is a fine balance between the two.

Utilisation of the drill ships and jackups has dropped down to around 85% from around 100% last summer, with day rates for drillships reduced by around 10% since the summer, while jackups in Europe dropping by a similar amount.

Figure 3: Source: HIS Petrodata Offshore Rig Day Rate Trends, March 17th, 2015

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The lower rig rates only help if the rig rate was not agreed in advanced and contracted out, although there is the potential to renegotiate existing leases. FOGL announced last week that it had cancelled a second well drilling program, under Nobel energy's suggestion, in order to focus on the most prospective drilling targets to potentially save against future drilling. It is unlikely that all the current wells being drilled under the program in the Falkland Islands (March 2015) will see the benefits of lower rig rates, with over 6 wells to be drilled in the region at an estimated cost of $50 million each. However, the companies are likely to have previously secured and set aside funding for drilling in the region. The benefit of lower rig rates is only likely to be for future drilling programs in the region and by that time oil prices could be back up, and with them the day rates.

Summary

There is no doubt that oil and gas companies have to adapt to the changing oil prices and this will often be in the form of reducing capex. The Falkland Islands exploration and development activities will therefore feel the impact of low oil prices once again, which would have potentially changed the economy of the territory.

There are still reasons to be optimistic within the Falkland Islands oil and gas sector. Drilling activities are continuing despite the low prices, recent success on wells after the Sea Lion discovery and an attractive fiscal regime are likely to ensure continued interest. The low price environment has likely ensured those companies which are active in the Falkland Islands are utilising their resource in a more cost-effective manner.

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Are oil and gas companies across the world 'complacent' on financial risk of suppliers?

Written by Malcolm Wilson from Achilles

It's no secret that the oil and gas industry is suffering from financial pressure, with firms racing to make efficiencies and achieve 'quick win' cost savings.

The fall-out from the tumbling oil price has been punishing, painful for those losing jobs, and highly public. But the risks behind the scenes could be just as damaging.

A recent survey of oil and gas professionals across the world revealed that despite suffering from the financial failure of suppliers, many companies are not taking basic steps to collect financial information from suppliers.

One quarter of oil and gas firms said that during the last year, they had experienced disruption to their supply chain from financial problems associated with suppliers. Senior executives from oil and gas companies across the UK, USA, Spain, Brazil and The Nordics said these failures had also caused reputational and operational damage across their businesses.

Yet one in four (27%) large firms admitted they do not protect themselves from this risk - by gathering financial reports from their main contractors before issuing a tender or contract. Almost half (47%) don't obtain financial information for suppliers lower down the supply chain before considering them for work.

As a result, almost one in five (19%) oil and gas companies across the globe said they are not confident they are adequately managing the risks associated with their suppliers.

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Prevention is better than cure

Increasingly, businesses are expected to reveal potential risks in their supply chain, out of a duty to consumers and shareholders - such as the Sarbanes-Oxley legislation for public companies in the US.

In the wake of a series of high profile supply chain disruptions, industry does have a clear motivation to get to grips with financial risks. So, why wouldn't buying organisations protect themselves?

In our experience, there are three main problems - lack of people, processes and tools.

People - With staff numbers falling, it is quite right that C-level executives should be focusing on long term strategic development, not spending time contacting suppliers for financial reports and certificates. This work should be outsourced leaving others to focus on strategy.

Process - The survey also revealed that around one in five oil and gas firms don't have a proper process for pre-qualifying suppliers. In our experience, we also find oil and gas companies that choose to run their own internal supplier databases often suffer from having very messy supplier data - they overestimate the number of active suppliers and data is often out of date or unvalidated.

Tools - To really stay on top of risks oil and gas firms need a proper system with automated processes to gather information, as well as people on the end of a phone to help suppliers.

Need for change

There are clear, practical steps businesses can take to address this issue. But some oil and gas professionals must also look to change the culture of the industry - and adopt a more collaborative approach.

There is no competitive advantage in holding mandatory information about suppliers, so firms should work together to tackle the significant administrative burden of collecting, managing and updating information about suppliers.

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The oil and gas sector spends around 80% of revenue with suppliers but no supplier should be allowed to get off the starting blocks until it has proven its credentials in business critical areas such as financial status.

In our experience, oil and gas firms can most effectively tackle risks associated with suppliers when they agree common standards required of all contractors. Oil and gas firms are often reliant on the same suppliers - but in a network they can divide the time and cost of collecting, managing and updating business critical information about suppliers. With accurate data, buying organisations can protect themselves by proactively managing and mitigating risk.

Further, strengthening the supply chain also offers oil and gas companies a long-term sustainable way in which to grow and develop over the long term. The smartest companies don't see risk and compliance as a burden - it's an opportunity to set standards, protect from risks and drive innovation through the supply chain.

Recent news stories have shown the impact of supplier failure can be astronomical. The oil and gas sector cannot afford to ignore it and a sensible collaborative approach can reduce both cost and risk.

Malcolm Wilson is Director of Achilles FPAL - the community used by major buying organisations within the European Oil & Gas sector. It enables the oil & gas sector to use Achilles' proven supplier pre-qualification system to identify, pre-qualify and assess suppliers for tender opportunities and minimise risk within their supply chains.

Achilles manages a network of online portals used by the global oil and gas sector to manage supplier information and mitigate risks. More than 20,000 suppliers have completed online profiles of their business critical information such as compliance, which are then visible to the community of over 300 oil and gas buying organisations.

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What if Oil Is the Best Investment of 2015?

Written by Keith Schaefer from Oil & Gas Investments Bulletin

Investors can't say definitively that the price of oil bottomed in the third week of March, but some very recent data released by the International Energy Agency (IEA) that supports the premise that a bottom is in. More on that in a moment.

From a low near $43 per barrel WTI has been bumping around $60 per barrel this past week - a not insignificant increase of 40% over only a fifty day period of time.

As investors we need to try and figure out if this is a short term head fake or something that is sustainable and based on supply and demand fundamentals.

A Rally Despite Repeatedly Bearish American Inventory Numbers

The oil data point that is most closely watched on a weekly basis by oil traders is the Wednesday EIA inventory report.

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Week after week in 2015-up until the most recent (May 6) report-these inventory numbers have been unquestionably bearish.

U.S. inventory levels aren't just high relative to the trailing five year range, they are off-the-charts-high. When oil was in its mid-collapse stage in December 2014 inventory levels were still within that five year range. Today those inventory levels sit 100 million barrels above the highest level of the past five years experienced at this time of year.

Looking at this inventory chart in isolation would make you think that oil prices should have been driven right into the ground. Inventory levels are so high that there is talk from respectable sources that we may actually run out of places to put the stuff.

This is bearish on a level that we haven't seen before.

Yet oil has rallied. Why?

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The most recent monthly Oil Market Report from the IEA provides a few clues-clues that I have been writing about in recent weeks.

On April 14th I wrote a story entitled 'Surprise, Global Oil Demand is Surging...' and focused on the data that was available both in the United States as well as in China and India.

The IEA's April Oil Market Report which was released to the public this week confirms exactly what I wrote about nearly a month ago.

The IEA appropriately describes what is happening at 'The Plot Thickens'.

The IEA notes that there has been unexpected demand strength across the globe. Why there wouldn't be a positive demand reaction from a 50% decline in oil prices may be a bit perplexing to some, but nonetheless.

According to the IEA global year on year demand for oil increased by a 'surprising' 1.3 million barrels per day year on year in the first quarter of 2015.

The demand charge was particularly strong in Asia with deliveries of oil rising by 110,000 barrels per day in Korea, 200,000 barrels per day in India and 250,000 barrels per day in China.

The IEA noted that even Russia which is subject to punishing economic sanctions was able to grow its oil consumption in the first quarter.

The inventory chart referred to earlier with inventory levels that were completely off the charts presented an incredibly bearish picture for oil.

The demand side of the equation has a similar looking chart, but one that is decidedly bullish.

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Source of Chart: April 2015 IEA Monthly Oil Market Report

This chart depicts OECD gasoil/diesel demand for the first two months of 2015. Like the inventory chart, monthly oil demand is far above the five year average and range.

For the first time in four years OECD demand has grown for four consecutive months. Now that we are through refinery maintenance season and refining levels are higher we should see this demand growth show up in the inventory levels.

There was a reason that oil prices bottomed in March and started to rise despite continued bearish inventory data.

The Market figured out that oil demand was also soaring and I suspect also that it determined (also accurately) that U.S. production was flattening and heading into a decline.

If that trend continues, oil price and oil stocks could end up surprising everyone this year. There are six stocks that I think outperform the Market if this trend continues.

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26

U.S. Oil Market Update- Blame Canada!

Written by Nathan Weiss and Keith Schaefer from Oil & Gas Investments Bulletin

Where is all the oil coming from?

Oil inventories continue to surge, but U.S. production has flatlined for weekseven months.

I mean reallylook at these simple facts that have been staring the Market in the face for months:

1. Year-to-date (YTD) production in 2015 in the U.S. is only 160,000 bopd (barrels of oil per day) above December levelsmultiply that by 7 days a week to get 1.12 million barrels a week.

2. Demand in the U.S. is up by A LOT moredepending on which analysts/firm you want to believejU.S.t under 800,000 bopd. Refineries are running at record high throughputs jU.S.t to keep up (92.3% now vs. 5-yr average of 87.8%)!

Yet U.S. oil inventories continue to climbby a stunning 6.54 million barrels a week so far this yearalmost 300% over the typical December-May 1.71 million barrels per week. So U.S. production YTD only accounts for 17% of this. What gives?

This huge growth in inventories has caused some high profile analysts to call for $20 oil. The idea of oil storage becoming full in the U.S. caused a second big downleg in March in WTI pricesset in Cushing OKto a low of $42/barrel.

The reason behind this seeming paradox? When you look at the data, the creators of South Park got it right - we should really 'Blame Canada!'

Two new pipelines recently debottleneck crude flows from Canada to the Gulf of Mexico, resulting in a 13.99% increase (408,000 bopd) in U.S. crude oil imports from

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Canada in December (2.86 million additional barrels per week) that has largely been maintained. When you contrast that fact to the US oil inventory build in the first chart belowwell, that's almost all you need to know.

The vast majority of Canadian oil exports is heavy oil from the oilsands. While shale productionlight oilbegins to stall and fade, oilsands production will increase every year for at least the next five years. Growing production and heavy discounts (pun intended) will keep U.S. refiners processing all the Canadian heavy oilcalled Western Canada Select, or WCSthey can.

Even worse, crude oil imports are increasing as East and West coast refiners increase utilization, requiring them to consume additional seaborne crude (from Saudi Arabia and other places) in order to maintain their crude input blend slate: As U.S. refinery utilization increased from 89% to 92% over the past four weeks, total U.S. crude oil imports have averaged 7.56 million bopd, well above the YTD average of 7.26 million bopd and the March average of 7.25 million bopd.

Unless U.S. shale production falls dramatically (and soon), the U.S. crude inventory situation could get very ugly this summer as 1-3 million weekly builds continue - just as investors have written off full inventories as a risk factor!

The Development of U.S. Crude Oil Inventories

Analysts generally blame a surge in domestic crude oil production or reduced crude oil refinery utilization for the sharp growth in U.S. inventories over the past three months. Others hold onto various conspiracy theories, including the belief Saudi Arabia is intentionally stuffing crude oil (from various countries) into Gulf Coast storage facilities in order to drive down WTI crude prices and spare Brent pricing.

Before we truly 'Blame Canada!' let's put those theories to bed first: See this chart of U.S. crude oil inventories (DOESCRUD on Bloomberg), which clearly shows the surge began in early January:

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Rebasing the above chart to show the seasonality of inventories over the past five years (see below), shows that on average, U.S. crude oil inventories grow by a total of 36 million barrels (1.71 million barrels per week) from the end of December through the end of May.

So far in 2015, inventories have increased by a stunning 98.23 million barrels (6.54 million barrels per week) and unless U.S. shale production falls off a cliff in the next 3-5 weeks, are on track to grow by a further 20+ million barrels by the end of May!

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Is Surging U.S. Production to Blame?

The previous crude oil inventory charts show something clearly changed at the beginning of the year. While many blame surging U.S. crude oil production, the official EIA monthly data shows production increased from 9.11 million bopd in November to 9.32 million bopd in December, before declining to 9.19 million bopd in January.

The EIA's Weekly Petroleum Status Reports estimate U.S. crude oil production increased from 9.06 million bopd in November to 9.13 million bopd in December, 9.19 million bopd in January, 9.28 million bopd in February and 9.39 million bopd in March - as the following chart from Bloomberg shows (DOETCRUD ):

The continued growth in U.S. crude oil production isn't surprising given the lag between drilling activity and first production. The DOE weekly crude oil production data shows production has increased 0.26 million bopd since December.

More importantly, year-to-date production has only averaged 0.16 million bopd above December levels - an increase of just 1.12 million barrels per week. This says two things: First, the average increase in U.S. crude oil production year-to-date accounts for only 17% of the 6.54 million barrel per week average increase in inventories.

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Second-unless U.S. light oil production growth falls dramatically-and soon-weekly inventory builds should be increasing.

Refinery Utilization is Seasonally High

Low crude oil refinery utilization is another commonly-cited reason for rising crude inventories, but in reality refinery utilization (DOEPPERC on Bloomberg) sits at 92.3% compared to an average of 90.2% for all of 2014 and an average of just 87.8% over the past five years.

If we look at the seasonality of refinery utilization, we find the current utilization rate is a stunning 6.8% above the five year average of 85.3% for this week in April. Despite what is reported in the media, since November U.S. crude oil refineries have regularly been running at the highest utilization rates in more than five years, as the following chart shows:

If refinery runs revert to the mean, it would mean a big jump in inventories. All this means analysts are now potentially under-estimating the risk U.S. crude inventories will continue to grow through the summer.

Look at the calculations: U.S. crude oil refining capacity, as reported by the DOE, is 17.89 million bopd. The current refinery utilization rate of 92.3% equates to 16.51

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million bopd of total throughput. If refinery utilization increases to 94% this summer, roughly 1.0% above peak summer utilization rates of the past five years, total refinery throughput will increase by 0.30 million bopd (to 16.81 million bopd).

Even with the resulting increase in crude oil demand (+2.13 million barrels per week), U.S. light oil production would have to collapse or else crude oil inventories could continue to increase one to three million barrels per week during the peak refining season!

This is exactly what happened in December when U.S. refinery utilization rocketed to almost all-time highs (an unbelievable 94.2% for the month of Decembertraditionally the LOWEST time of year) as refiners took advantage of newly increased flow of cheap Canadian crude and built refined product inventories.

U.S. Crude Oil Imports from Canada (finally-BLAME CANADA!)

As mentioned in the intro-two new pipelines recently debottleneck crude flows to the Gulf of Mexico from Canada: Enbridge's 600,000 bopd Illinois-to-Oklahoma Flanagan South pipeline and Enterprise Products Partners' 450,000 bopd Oklahoma-to-Texas Seaway Twin.

While the Texas Seaway Twin pipeline was technically operational in October, the December start-up of the Flanagan South pipeline was necessary to feed it Canadian crude. Together these two new pipelines led to a 13.99% increase (408,000 bopd) in U.S. crude oil imports from Canada (DOCRCANA ) in December (2.86 million additional barrels per week), as the following chart shows:

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A 2.86 million barrel per week increase in crude oil imports from Canada accounts for 44.7% of the 6.54 million barrel per week growth in U.S. crude oil inventories so far this year. This is by far the largest single factor driving the sharp increase in inventories, yet it is rarely reported as the cause by the media or analysts.

The Outlook for Canadian Crude Oil Production

With WTI crude priced at $55.00 per barrel and Canadian heavy crude (WCS) priced $12.00 per barrel below WTI, it is easy to see why Gulf Coast refiners welcome all the Canadian heavy crude they can process - but how will Canadian crude oil producers respond to the current price environment?

Most of Canada's production is heavy oil from the oilsands in Alberta. BMO Nesbitt Burns, Canada's 2nd largest retail brokerage firm, says that despite a sharp drop in spending, they expect oil sands production to grow roughly 10% in 2015 to 2.4 million bopd as several new start-ups come on line.

And with break-even costs of $25/barrel for in-situ producers, that growth is not threatened.

Canada's National Energy Board (NEB) is calling for Canadian crude oil production

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to increase from 3.76 million bopd in 2014 (3.91 million bopd in December) to 3.89 million bopd in 2015, while OPEC is expecting Canadian production to increase by only 20,000 bopd in 2015.

First Energy suggests that overall Canadian oil production will continue to rise even with a decline in light oil production:

A wide array of Canadian production forecasts from Wall Street analysts effectively predict production will be flat. This is what overall Canadian oil production looks like in the last three years:

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Conclusions

Oil prices have rallied the past few weeks as investors believe (for various reasons) the worst of the U.S. inventory builds are behind U.S. That's true, but it's still unclear how much U.S. crude oil production will decline or that refiners will be able to consume all of the crude available this summer.

But Canada's oil supply continues to increase, and more of it is finding a way into the U.S. As a result, U.S. crude oil inventory builds could continue through the peak summer refining season - possibly at a rate of 1-3 million barrels per week.

This negative surprise could lead to another leg down in crude prices (particularly WTI) as investors (eventually) realize just how oversupplied the North American market is.

Even worse, crude oil imports are increasing as East and West coast refiners increase utilization, requiring them to consume additional seaborne crude in order to maintain their crude input blend slate: As U.S. refinery utilization increased from 89% to 92% over the past four weeks, total U.S. crude oil imports (DOEICESP on Bloomberg) have averaged 7.56 million bopd, well above the YTD average of 7.26 million bopd and the March average of 7.25 million bopd.

The U.S. crude inventory situation could get very ugly this Summer - just as investors have written off full inventories as a risk factor!

And you can Blame Canada!

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Why We Have an Oversupply of Almost Everything (Oil, labor, capital, etc.)

Written by Gail Tverberg from Our Finite World

The Wall Street Journal recently ran an article called, Glut of Capital and Labor Challenge Policy Makers: Global oversupply extends beyond commodities, elevating deflation risk. To me, this is a very serious issue, quite likely signaling that we are reaching what has been called Limits to Growth, a situation modeled in 1972 in a book by that name.

What happens is that economic growth eventually runs into limits. Many people have assumed that these limits would be marked by high prices and excessive demand for goods. In my view, the issue is precisely the opposite one: Limits to growth are instead marked by low prices and inadequate demand. Common workers can no longer afford to buy the goods and services that the economy produces, because of inadequate wage growth. The price of all commodities drops, because of lower demand by workers. Furthermore, investors can no longer find investments that provide an adequate return on capital, because prices for finished goods are pulled down by the low demand of workers with inadequate wages.

Evidence Regarding the Connection Between Energy Consumption and GDP Growth

We can see the close connection between world energy consumption and world GDP using historical data.

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This chart gives a clue regarding what is wrong with the economy. The slope of the line implies that adding one percentage point of growth in energy usage tends to add less and less GDP growth over time, as I have shown in Figure 2. This means that if we want to have, for example, a constant 4% growth in world GDP for the period 1969 to 2013, we would need to gradually increase the rate of growth in energy consumption from about 1.8% = (4.0% - 2.2%) growth in energy consumption in 1969 to 2.8% = (4.0% - 1.2%) growth in energy consumption in 2013. This need for more and more growth in energy use to produce the same amount of economic growth is taking place despite all of our efforts toward efficiency, and despite all of our efforts toward becoming more of a 'service' economy, using less energy products!

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To make matters worse, growth in world energy supply is generally trending downward as well. (This is not just oil supply whose growth is trending downward; this is oil plus everything else, including 'renewables'.)

There would be no problem, if economic growth were something that we could simply walk away from with no harmful consequences. Unfortunately, we live in a world where there are only two options-win or lose. We can win in our contest against other species (especially microbes), or we can lose. Winning looks like economic growth; losing looks like financial collapse with huge loss of human population, perhaps to epidemics, because we cannot maintain our current economic system.

The symptoms of losing the game are the symptoms we are seeing today-low commodity prices (temporarily higher, but nowhere nearly high enough to maintain production), not enough good paying jobs for common workers, and lack of investment opportunities, because workers cannot afford the high prices of goods that would be required to provide adequate return on investment.

How We Have Won in Our Contest with Other Species-Early Efforts

The 'secret formula' humans have had for winning in our competition against other species has been the use of supplemental energy, adding to the energy we get from food. There is a physics reason why this approach works: total population by all species is limited by available energy supply. Providing our own external energy

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supply was (and still is) a great work-around for this limitation. Even in the days of hunter-gatherers, humans used three times as much energy as could be obtained through food alone (Figure 1).

Earliest supplementation of food energy came by burning sticks and other biomass, starting one million years ago. Using this approach, humans were able to gain an advantage over other species in several ways:

1. We were able to cook some of our food. This made a wider range of plants and animals suitable for food and made the nutrients from these foods more easily available to our bodies.

2. Because less energy was needed for chewing and digesting, our bodies could put energy into growing a larger brain, thus giving us an advantage over other animals.

3. The use of cooked food freed up time for such activities as hunting and making clothes, because less time was needed for chewing.

4. Heat from burning plant material could be used to keep warm in cold areas, thereby extending our range and increasing total human population that could be supported.

5. Fire could be used to chase off predatory animals and hunt prey animals.

Our bodies are now adapted to the need for supplemental energy. Our teeth our smaller, and our jaws and digestive apparatus have shrunk in size, as our brain has grown. The large population of humans that are alive today could not survive without

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supplemental energy for many purposes, such as cooking food, heating homes, and fighting illnesses that spread when humans are in as close proximity as they are today.

Our Modern Formula For Winning the Battle Against Other Species

In my view, the formula that has allowed humans to keep winning the battle against other species is the following:

1. Use increasing amounts of inexpensive supplemental energy to leverage human energy so that finished goods and services produced per worker rises each year.

2. Pay for this system with debt, because (if supplemental energy costs are cheap enough), it is possible to repay the debt, plus the interest on the debt, with the additional goods and services made possible by the cheap additional energy.

3. This system gradually becomes more complex to deal with problems that come with rising population and growing use of resources. However, if the output of goods per worker is growing rapidly enough, it should be possible to pay for the costs associated with this increased complexity, in addition to interest costs.

4. The whole system 'works' as long as the total quantity of finished goods and services rises rapidly enough that it can fund all of the following: (a) a rising standard of living for common workers so that they can afford increasing amounts of debt to buy more goods, (b) debt repayment, and interest on the debt of the system, and (c) and an increasing amount of 'overhead' in the form of government services, medical care, educational services, and salaries of high paid officials (in business as well as government). This overhead is needed to deal with the increasing complexity that comes with growth.

The formula for a growing economy is now failing. The rate of economic growth is falling, partly because energy supply is slowing (Figure 3), and partly because we need more and more growth of energy supply to produce a given amount of economic growth (Figure 2). With this lowered world economic growth, the amount of goods and services being produced is not rising fast enough to support all of the functions that it needs to cover: interest payments, growing wages of common workers, and growing 'overhead' of a more complex society.

Some Reasons the Economic Growth Cycle is Now Failing

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Let's look at a few areas where we are reaching obstacles to this continued growth in final goods and services. An overarching problem is diminishing returns, which is reflected in increasingly higher prices of production.

1. Energy supplies are becoming more expensive to extract.

We extract the easiest to extract energy supplies first, and as these deplete, need to use the more expensive to extract energy supplies. We hear much about 'growing efficiency' but, in fact, we are becoming less efficient in the production of energy supplies.

In the US, EIA data shows that we are becoming less efficient at coal production, in terms of coal production per worker hour (Figure 5)

With oil, growing inefficiency is shown by the steeply rising cost of oil exploration and production since 1999 (Figure 6).

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Thus, it is for a fairly recent period, namely the period since about 2000, that we have been encountering rising costs both for US coal and for worldwide oil extraction.

The extra workers and extra costs required for producing the same amount of energy counteract the tendency toward growth in the rest of the economy. This occurs because the rest of the economy must produce finished products with fewer workers and less resources as a result of the extra demands on these resources by the energy sector.

2. Other materials, besides energy products, are experiencing diminishing returns.

Other resources, such as metals and other minerals and fresh water, are also becoming increasingly expensive to extract. The issue with mineral ores is similar to that with fossil fuels. We start with a fixed amount of ores in good locations and with high mineral percentages. As we move to less desirable ores, both human labor and more energy products are required, making the extraction process less efficient.

With fresh water, the issue is likely to be a need for desalination or long distance transport, to satisfy the needs of a growing population. Workarounds again involve more human labor and more resource use, making the production of fresh water less efficient.

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In both of these cases, growing inefficiency leaves the rest of the economy with less human energy and less energy products to produce the finished goods and services that the economy needs.

3. Growing pollution is taking its toll.

Instead of just producing end products, we are increasingly finding ourselves fighting pollution. While this is a benefit to society, it really is only offsetting what would otherwise be a negative. Thus, it acts like overhead, rather than producing economic growth.

From the point of view of workers having to pay for higher cost energy in order to fight pollution (say, substitution of a higher cost energy source, or paying for more pollution controls), the additional cost acts like a tax. Workers need to cut back on other expenditures to afford the pollution control workarounds. The effect is thus recessionary.

4. The amount of 'overhead' to the world economy has been growing rapidly in recent years, for a number of reasons:

The amount of overhead is growing because we are reaching natural barriers. For example, population per acre of arable land is growing, so we need more intensity of development to produce food for a rising population.

With greater population density and increased bacterial antibiotic resistance, disease transmission becomes a more of a problem.

Increasing education is being encouraged, whether or not there are jobs available that will make use of that education. Education that cannot be used in a productive way to produce more goods and services can be considered overhead for the economy. Educational expenses are frequently financed by debt. Repayment of this debt leads to a decrease in demand for other goods, such as new homes and vehicles.

We have more elderly to whom we have promised benefits, because with the benefit of better nutrition and medical care, more people are living longer.

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4. We are reaching debt limits.

As economic growth has slowed, we have been adding more and more debt, to try to mitigate the problem. This additional debt becomes a problem in many ways: (a) without cheap energy to leverage human labor, there are not many productive investments that can be made; (b) the addition of more debt leads to a need for more interest payments; and (c) at some point debt ratios become overwhelmingly high.

At least part of the slowdown in economic growth that we are seeing today is coming from a slowdown in the growth of debt. Without debt growth, it is hard to keep commodity prices high enough. Investment in new manufacturing plants is also affected by low growth in debt.

Reasons for Confusion in Understanding Our Current Predicament

1. Not understanding that all of the symptoms we are seeing today are manifestations of the same underlying 'illness'. Most analysts think that the economy has stubbed its toe and has a headache, rather than recognizing that it has a serious underlying illness.

2. Academia is focused way too narrowly, and tied too closely to what has been written before. Academics, because of their need to write papers, focus on what previous papers have said. Unfortunately, previous papers have not understood the nature of our problem. Academics have developed models based on our situation when we were away from limits. The issues we are facing cover such diverse subjects as physics, geology, and finance. It is hard for academics to become knowledgeable in many areas at once.

3. Models that seemed to work before are no longer appropriate. We take models like the familiar supply and demand model of economists and assume that they represent everlasting truths.

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Unfortunately, as we get close to limits, things change. Both wage levels and debt levels have an impact on demand; the quantity goods available is also affected by diminishing returns. The model that worked in the past may be totally inappropriate now.

Even a complex model like the climate change model being used by the IPCC is likely to be affected by financial limits. If near-term financial limits are to be expected, IPCC's estimate of future carbon from fuels is likely to be too high. At a minimum, the findings of the IPCC need to be framed differently: climate change may be one of a number of problems facing those people who manage to survive a financial crash.

4. Too much wishful thinking.

Everyone would like to present a positive result, especially when grants are being given for academic research will support some favorable finding.

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A favorite form of wishful thinking is believing that higher costs of energy products will not be a problem. Higher cost energy products, whether they are renewable or not, are a problem for many reasons:

They represent growing inefficiency in the economy. With growing inefficiency, we produce fewer finished goods and services per worker, not more.

Countries using more of the higher cost types of energy become less competitive in the world market, and because of this, may develop financial problems. The countries most affected by the Great Recession were countries using a high percentage of oil in their energy mix.

The amount workers have available to spend is limited. If a worker has $100 to spend on energy supply, he can buy 100 times as much in energy supplies priced at $1 as he can energy supplies priced at $100. This same principle works even if the cost difference is much lower-say $3.50 gallon vs. $3.00 gallon.

5. Too much faith in, 'We pay each other's wages.'

There is a common belief that growing inefficiency is OK; the wages we pay for unneeded education will work its way through the system as more wages for other workers.

Unfortunately, the real secret to economic growth is not paying each other's wages; it is growing output of finished products per worker through increased use of cheap energy (and perhaps technology, to make this cheap energy useful).

Increased overhead for the system is not helpful.

6. An 'upside down' peak oil story.Most people in the peak oil community believe what economists say about supply and demand-namely, that oil prices will rise if there is a supply problem. They have not realized that in a networked economy,

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wages and prices are tightly linked. The way limits apply is not necessarily the way we expect. Limits may come through a lack of good paying jobs, and because of this lack of jobs, inability to purchase products containing oil.

The connection between energy and jobs is clear. Good jobs require the use of energy, such as electricity and oil; lack of good-paying jobs is likely to be a manifestation of an inadequate supply of cheap energy. Also, high paying jobs are what allow rising buying power, and thus keep demand high. Thus, oil limits may appear as a demand problem, with low oil prices, rather than as a high oil price problem.

In my opinion, what we are seeing now is a manifestation of peak oil. It is just happening in an upside down way relative to what most were expecting.

Conclusion

One way of viewing our problem today is as a crisis of affordability. Young people cannot afford to start families or buy new homes because of a combination of the high cost of higher education (leading to debt), the high cost of fuel-efficient new cars (again leading to debt), the high cost of resale homes, and the relatively low wages paid to young workers. Even older workers often have an affordability problem. Many have found their wages stagnating or falling at the same time that the cost of healthcare, cars, electricity, and (until recently) oil rises. A recent Gallop Survey showed an increasing share of workers categorize themselves as 'working class' rather than 'middle class.'

It is this affordability crisis that is bringing the system down. Without adequate wages, the amount of debt that can be added to the system lags as well. It becomes impossible to keep prices of commodities up at a high enough level to encourage production of these commodities. Return on investment tends to be low for the same reason. Most researchers have not recognized these problems, because they are narrowly focused and assume that models that worked in the past will continue to work today.

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49

Is the slowdown in productivity growth a result of energy costs?

Written by Kurt Cobb from Resource Insights

Slowing productivity growth in the United States has been in the news in recent months. It has become a concern to policymakers because they believe it is one of the primary contributors to a middle-class economic squeeze according to the annual report of the White House Council of Economic Advisors.

Simply put, productivity growth refers to the growth in economic output per worker or more precisely, per hour of work. When this growth slows, the potential for real wage increases diminishes since the growth in wages typically reflects the ability of workers to create more output per unit of time.

To the obstensibly naive observer the following idea may seem a plausible explanation: Higher-cost energy inputs into the production of goods and services reduce productivity growth because the economic output per dollar of energy consumed declines. And, though energy inputs aren't the only thing to consider, they are important. The high energy prices of the last decade or so may be, in part, responsible for low productivity growth. (Conversely, low energy costs would imply more output per dollar of energy consumed.)

But strangely, almost all economic models for productivity consider only so-called 'tangible' factors, that is, labor and capital. In the bizarro world of modern economics, energy and materials are not considered 'tangible.'

Now, the way in which that productivity growth which is attributable to 'technological advances' is typically calculated is to add up contributions to productivity growth from labor and capital (machines, buildings, vehicles, tools of any kind) and then subtract this sum from the known amount of total productivity growth. What is left is the so-called 'residual' which is presumed to result from 'technological advances' caused by increases in human knowledge. These advances and the increases in capital per

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worker are assumed to be the drivers of productivity growth.

Let me explain this from a slightly different angle: Obviously, if you work more hours, you will be more productive. But your output per hour will remain the same, barring some new input such as better, more efficient machines to work with or more efficient techniques, both resulting presumably from an increase in knowledge.

Note that there is no way to measure this 'knowledge factor' directly. It is merely assumed that the unknown portion of productivity growth comes from 'technological advancement.'

But, energy researchers asked long ago whether productivity growth might be affected by changes in the quality and cost of energy inputs. Authors of a paper entitled 'Energy and the U.S. Economy: A Biophysical Perspective' which appeared in Science in August 1984 noted the tight correlation between economic growth and energy consumption. They also noted that labor productivity increased with increasing energy consumption per employee. While not dismissing the effects of technological change, they believe that energy has had a central role in the persistent rise in labor productivity witnessed for most of the last century up to the time of publication:

'From an energy perspective, productivity gains are facilitated by technical advances that enable laborers to empower their efforts with greater quantities of high-quality fuel embodied in and used by capital structures.'

Notice the use of the term 'embodied.' The researchers recognized the energy necessary to produce the capital equipment used by workers. This is called the 'embodied energy.' The researchers also noted the following:

'We found that in the U.S. manufacturing sector, output per worker-hour is closely related to the quantity of fuel used per worker-hour. A similar relation exists in the U.S. agricultural industry.'

The mining sector also fit this pattern. While productivity per worker-hour has increased or, in some cases, merely stayed flat, the energy data showed just how much more energy was needed to achieve stable or growing productivity:

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'Technical improvements in the extractive sectors have made available previously uneconomic deposits only at the expense of more energy-intensive forms of capital and labor inputs. Physical output per kilocalorie of direct fuel input in the U.S. metal mining industries has declined 60 percent since 1939, although a few exceptions to that trend are known. The energy cost per ton of metal at the mine mouth for industrially important metals such as copper, aluminum, and iron has risen sharply as their average grade declined. For all U.S. mining industries (including fossil fuels), output per unit input of direct fuel declined 30 percent since 1939.'

These findings suggest that fuel costs, fuel quality and fuel availability can be limiting factors in productivity across the economy. The idea that energy inputs used in production are central to productivity isn't so counterintuitive after all. And yet, in a sampling of recent coverage of the productivity issue, not one piece mentioned energy. (See here, here, here and here.)

One of the authors of the research cited above, Charles A. S. Hall (now retired), says that the report's findings need to be updated to see whether the relationships his team discovered still hold. It would seem wise to follow up given the exceptionally slow productivity growth associated with the period of rising energy prices before the crash in 2008 and to a certain extent with high average daily oil prices from 2011 through late 2014 (though, as one might expect, this is not even mentioned as a possible explanation in the piece cited.)

Whether such updated research would confirm the original findings can't be known. Whether it would make any difference to mainstream productivity models is known. Such new findings will make no difference whatsoever until the economics profession recognizes the central role of energy in the productivity of the workforce.

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Who's who in steam Written by Stephen A. Brown from The Steam Oil Production Company Ltd

When we have been talking with potential investors and partners about steaming the Pilot oil field, we have often been asked who else steams oilfields, and does anyone do it offshore?

Most people knew about the Canadian oil sands and the steam assisted gravity drainage (SAGD) schemes which are coming on stream at pace over in Canada. But not so many were aware of the steam flood projects which have been very successful in California, Venezuela, Indonesia and right here in Europe.

So we have tried to collate some data, though I have to say it has been a tad elusive and I am quite sure that the information we have is incomplete and not entirely accurate. We started with the Oil & Gas Journal 2014 EOR report and added up all the steam projects by operator. All the production figures in the tables in the OGJ report are from 2013 and are gross (before royalty and partner interests); so we adopted that convention and from our perspective that was what mattered, as what we wanted to know was, who are the pre-eminent operating companies in steam flooding? Actually we already knew the first answer to that question - the pre-eminent company is Chevron. They already produce over 300,000 bbls per day from steam flood projects and are busy investing in new projects around the world. Funny enough, Sefton Resources of old didn't get a mention, not even as a rounding error.

But we looked at the numbers for the SAGD projects in Alberta and those looked a tad light to us so we went through every in-situ performance report posted on the Alberta Energy regulator's website and extracted the 2013 production figures as best we could. There was quite a lot of Canadian production missing from the Oil and Gas Journal's report, as well as projects coming on stream in 2014 and 2015 which we haven't counted as yet.

Then we noticed that some big projects we knew of in the Middle East, Mukhaizna, Qarn Alam and Wafra were missing, so we added in the production figures for those too. We knew that Russia did steam some oilfields in the past, in fact the textbook on 'Thermal Methods of Petroleum Production' was written

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by Messrs Baibakov & Garushev, but finding up to date information has been difficult. The Yarega field is still produced using a combination of mining and steam and Schlumberger are involved in helping Lukoil boost production there towards nearly 70,000 bbls/day. A number of fields in Sakhalin and Azerbaijan were also steamed in the sixties and seventies but we haven't found out if that still continues. CNPC is implementing steam flood and SAGD technologies in the Liahoe oil province in China and is producing at least 20,000 bbls/day from their initial projects. CNOOC is producing some oil using steam technologies offshore in the shallow waters of Bohai Bay, but we couldn't find a production figure for those fields, though they are quite a player in the SAGD business after their $15 billion acquisition of Nexen in 2012.

Nevertheless, we added in all the figures we could find for Russia, China and the Middle East although in some cases we aren't really quite sure which year they might relate to.

We were also really interested in the Emeraude field in Congo, as that is the only other offshore steam project we know of in similar water depths to our Pilot project; Emeraude is in 65m of water, whilst Pilot is in 80m of water. It took a bit of extra-special googling to find the data on the Congolese Conseil National du Credit website, but we got there and confirmed that Perenco are successfully producing about 9,000 bbl/day from what is really quite a difficult carbonate and siltstone reservoir. Some of that is from conventional production but Perenco say the steam flood is now operating on four steam injection wells and nine producers so there must be a decent contribution from steam flood to the overall rate.

Perenco's Emeraude MOAB platform, Congo, Courtesy of and Overdick GmbH & Co KG

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When all is said and done, we get pretty close to 2 million bbls per day of steam enabled oil production around the world. Chevron tops the list, PDVSA with all that heavy oil in the Orinoco belt comes next, then we have all the SAGD companies - Cenovus, Suncor, CNRL and the rest. Occidental are making huge strides with the Mukhaizna project in Oman and Exxonmobil, through Imperial, operate one of the biggest cyclic steam stimulation projects in Canada as well. Finally there is a surprising entry at number 9 in the hit parade by Lukoil with their combined mining and SAGD technique.

Close to home Shell and Wintershall are steam flooding the Schoonebeek and Emlichheim field in Holland and Germany. (See how I kept the word 'field' singular so that the sharp eyed among you would realise that it is just one field which crosses an international boundary.)

So here is the Steam Oil Production league table, do let us know if we have missed someone important or if we got your company's figure terribly wrong.

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The Stock to Own if US Oil Production Stays Stronger for Longer

Written by Keith Schaefer from Oil & Gas Investments Bulletin

The Opaque World of Crude Oil

The latest EIA stats painted a seemingly bullish picture for North American crude oil right now. Crude prices have rebounded from the March re-test of the low, US production seems to finally be falling and Cushing storage levels are starting to draw down. The story is all good for the North American producer...or is it?

The strong rally in WTI from Mar 17 to May 5 can be largely explained by hedge fund short covering. In mid March, hedge fund short positions peaked with WTI-linked futures and options amounting to 209 million barrels of oil. Since that time, hedge fund short positions have declined more than 55% to roughly 93 million barrels.

During this same period of time hedge funds only added 2% to long positions in oil or roughly 7 million barrels. Not to say that fundamentals don't play a part in price, but the hedge funds tend to accelerate and/or exacerbate the moves in price in both directions.

There isn't a material amount of short positions being added to or covered now, nor is there much activity on the long side either, which is one reason WTI has stalled out in the $60 range for the last month. The hedge funds seem to be moving to the sidelines until they can predict which direction crude will move from here.

Next up, let's look at the domestic production drop reported in last week's EIA data. Looking at this data on a weekly basis can be deceptive. Part of the most recent weekly decline was due to curtailed Alaskan production due to full storage tanks at

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Valdez (estimated to be ~90,000 b/d) and some of the decline is a function of offshore Gulf Coast maintenance (peaking at roughly ~200,000 b/d).

That would mean Lower 48 production is still as high as ever.

The Gulf Coast maintenance will have a ramp up and ramp down period so it will be difficult to clearly assess its weekly impact, while the Alaska situation is expected to clear itself up for next week's stats. It's plausible that over the next 1-2 weeks we could see US production rise back to peak 2015 levels, which has to be disappointing to oil bulls who were expecting the sharp production declines in light of the dramatic drop in North American rig counts.

Lastly, Cushing storage draws aren't necessarily bullish right now as they aren't even drawing down as quickly as last year. This means that on a year over year basis, the storage surplus is still increasing. Given the fears the market had in March and April of US storage reaching capacity, any storage draw is viewed as bullish in absolute terms...but perhaps we aren't out of the woods yet.

Of course all this is analysis is predicated on the information available to the EIA. Along with the EIA and other data resources like OPEC and IEA the unfortunate reality is that all the information that is published today is imperfect at best and in many cases, is simply an educated guess.

National Oil Companies (NOCs) have no need or desire to report any of their activities. It's all but guaranteed we aren't getting accurate information out of Libya, Iraq, Yemen, Iran, etc. All of the data above would tend to be bearish.

It's interesting to me that for all the specialized, big name firms who analyze one of the planet's biggest industries-no one is completely accurate. It's not even absolutely necessary to ascertain who is the most correct. You have to understand who the Market believes is the most accurate-because a shift in direction from the Market

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leader will likely be the signal as to which direction prices go next.

In the meantime, because of the opacity of information in the crude oil market, the individual investor has to be vigilant about what stocks you own. The stronger the underlying value of the company, the less it will be hit by a downward move in prices and the more it should benefit from a price upswing. For energy investors, it means mostly owning the leaders among the producers and other sub-sectors.

But what if you own a stock that benefits from a lower oil price?

Now, the one FACT I see in the oil market is that the US rig count is down some 60%, while oil production is barely off 1%.

At the beginning of 2015, I suggested US oil production would stay stronger for longer than the Market expected. So far that's happening-despite a much stronger drop in rig count than anyone thought.

If this trend continues, there's one stock-A Market Leader-you want to own - CLICK HERE to get my full report.

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