Oilvoice Magazine - July 2015

Edition Forty - July 2015

Pump oil hard now or live to regret production cuts Doing the maths on Horse Hill The Texas Natgas Massacre

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James Bull Guest Editor, Taipan Resources Issue 40 – July 2015

The romance of oil and gas exploration (from OilVoice Acorn House 381 Midsummer Blvd Milton Keynes MK9 3HP Tel: +44 207 993 5991 Email: press@oilvoice.com Advertising/Sponsorship Mark Phillips Email: mark@oilvoice.com Tel: +44 207 993 5991 Social Network Facebook Twitter Google+ Linked In

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a geologist’s perspective) can “drive a company into bankruptcy” I once heard a CEO say; a bold statement but in many ways a true one. High risk exploration has become considerably less attractive in the last 6-12 months for reasons I believe don’t need any introduction or explanation. This has made many boards come together and decide it is a wise decision to change the direction of companies towards creating a more production and appraisal driven portfolio which will allow for a net income and the ability to still play with a little romance on the side.

However, it is very much a chicken and egg scenario especially for small independent exploration companies finding it difficult to raise capital without a deal on the table, but how are you meant to be in the running for a deal without any capital… I believe a great analogy for this is when you are in your junior years and you struggle to get a job because you have a lack of experience, but how are you meant to get any experience if you aren’t given the chance.

Whether it’s production, appraisal or exploration where your still set lies, a large increase of jobs on OilVoice this month maybe at least one area of our ‘romantic’ industry where we can move away from this chicken and egg scenario.

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Table of Contents 6 Rig Count Decreases A Little: Don't Get Too Excited

by Art Berman Pump Oil Hard Now Or Live To Regret Production Cuts

by John Richardson

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No, BP, the U. S. did NOT surpass Saudi Arabia in oil production

by Kurt Cobb

11

BP Data Suggests We Are Reaching Peak Energy Demand

by Gail Tverberg

15

The Texas Natgas Massacre

by Keith Schaefer

31

The energy revolution will not be televised

by Kurt Cobb

39

Nuclear Future: How Japan's Oil Consumption is changing

by Jeff Nevil

45

Palantir Forward Curve - 2015 June

by Bowen Gao

47

OPEC's Dilemma: The Long View

by Art Berman

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Survival of the smartest - investment in innovation continues despite drop in price of oil

by Douglas Rankin

53

US futures market rally boosts US and OPEC oil output

by Paul Hodges

57

Doing the maths on Horse Hill

by Stephen A. Brown

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Rig Count Decreases A Little: Don't Get Too Excited Written by Art Berman from The Petroleum Truth Report The U.S. rig count dropped by 10 rigs this week after only falling by 3 last week. No doubt some analysts will say that this increase is somehow important and that a return to normal-i.e., high oil prices-is around the corner.

Well, don't get too excited because the rig count that matters-the horizontal Bakken, Eagle Ford and Permian plays-only fell by 2 rigs after not falling last week. This is a normal fluctuation when oil is $100/barrel.

Table 1. Rig count summary by play through May 29, 2015. Source: Baker Hughes & Labyrinth Consulting Services, Inc. The rig count decline is effectively over as shown below in Figure 1 .

Figure 1. Tight oil horizontal rig counts. Source: Baker Hughes & Labyrinth Consulting Services, Inc.

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Production has fallen and will fall more but rig count is the wrong measure at this time. The real measure is capital given to U.S. tight oil companies. And there seems to be plenty of really stupid capital that thinks that investing now means buying low.

Good luck with that once oil prices fall.

Figure 2. Bakken, Eagle Ford and Permian 'Shale' tight oil production. Source: Drilling Info & Labyrinth Consulting Services, Inc. There have been a steady stream of articles championing the ingenuity of U.S. tight oil producers for figuring out how to maintain production with fewer rigs. It doesn't strike me as ingenious to produce more oil at low prices that ensure losing money.

OPEC will meet on Friday (June 5, 2015) and most doubt that a production cut will result. If that is the outcome, expect the recent rally in oil prices to end badly. If producers cared about their investors and share holders, they would be slashing production by shutting in wells. That might help oil prices rebound sooner and then, they could sell the oil at a profit instead of losing money while celebrating their own ingenuity.

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Pump Oil Hard Now Or Live To Regret Production Cuts Written by John Richardson from ICIS

OIL producers face a very straightforward choice: Pump crude as hard as possible right now or run the risk of your most important economic asset being left in the ground for good.

One of the reasons is that, regardless of what you might think about the science behind claims that burning fossil fuels has the potential to cause devastating climate change, both government and public opinion has decisively shifted.

For example, the leaders of the G7 group of nations recently made a commitment to cut greenhouse gases by 40-70% by 2050 from their 2010 levels, along with

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phasing-out all fossil fuel emissions by the end of the century. And remarkably, even a majority of Republican voters in the US are in favour of a carbon tax, provided the money raised is used to fund research into renewable energy.

The other reason for pumping oil as hard as possible over the next few years will be a growing realisation that a secular, long term decline in global economic growth makes very affordable energy absolutely essential. The cheaper that oil is over the next decade, the greater its consumption level at a time when it will face increasing pressure from the affordability issue, and from substitution by natural gas and renewables for environmental reasons.

Saudi Arabia appears to have already adopted the approach of maximising production before it is too late. It is already pumping 10.3 million barrels a day, a 30year-high. This could be increased to as much as 12.3 million a barrel, according to the International Energy Agency.

The lower outlook for oil prices 'turns oil in the ground in Saudi from an appreciating resource into a depreciating resource. If it's depreciating, you produce it as fast as you can,' said Seth Kleinman, head of energy strategy at Citigroup.

What other choice does the Saudi government realistically have, seen as almost 50% of Saudi Arabia's population in 2013 was under 25 years of age, with unemployment in that demographic at 12%?

It has to generate as much money as possible from oil sales to pay all the jobcreation schemes essential for preventing major social unrest. And here are some other statistics: energy products account for 90% of Saudi export exports, with the oil industry generating45% of GDP. In other words, Saudi Arabia has no other way of footing the bill for creating all of this employment.

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At the level of individual companies it also makes a lot of economic sense to pump now rather than cut back and regret later.

In Canada, companies there plan to still increase output by 156,000 barrels a day each year until 2020, despite the fall in oil prices, said the Canadian Association of Petroleum Producers.

Just as is the case across the border with US shale oil, cutting back on production in Canada doesn't add up as a few dollars of returns on a barrel of oil to pay-down debt are better than no dollars at all.

In another parallel with US shale oil, Canadian tar sands producers are ferociously cutting costs in order to keep production at as high a level as possible. Suncor Energy plans to, for instance, replace 800 dump truck drivers with automated trucks, which will save $200,000 per employee.

Here is the other thing about the tar sands industry: 85% of these Canadian reserves would have to be left in the ground if the world is to avoid the 2 centigrade average temperature rise seen as the tipping point towards dangerous levels of climate change, as the tar-sands process is very energy intensive, according to the University College of London.

So, just like Saudi Arabia, Canada's tar sands producers need to fill as many barrels as possible with oil right now, before a global price on carbon price forces them to leave their No1 asset in the ground.

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No, BP, the U. S. did NOT surpass Saudi Arabia in oil production Written by Kurt Cobb from Resource Insights

Even the paper of record for the oil industry, Oil & Gas Journal, got it wrong. With the release of the latest BP Statistical Review of World Energy, media outlets appeared to be taking dictation rather than asking questions about which countries produced the most oil in 2014.

If they had asked questions, they would have ended up with a ho-hum headline announcing that last year Russia at 10.1 million barrels per day (mbpd) and Saudi Arabia at 9.7 mbpd were once again the number one and number two producers of crude oil including lease condensate (which is the definition of oil). The United States at 8.7 mbpd remained in third place.

The most important question they could have asked is this: How is BP defining oil? It turns out that oil according to the BP definition includes something called natural gas liquids which includes lease condensate--very light hydrocarbons that come from actual oil wells and are included in the oil refinery stream--and natural gas plant liquids which come from natural gas wells and include such things as ethane, propane, butane and pentanes. Only a small portion of natural gas plant liquids are suitable substitutes for oil.

Production of natural gas plant liquids in the United States has grown rapidly as a result of increasing exploitation of natural gas in deep shale deposits, so-called shale gas. These liquids are useful, but they are not oil and only displace oil in a minor way. Moreover, their energy content is around 65 percent that of crude oil and so counting barrels of natural gas plant liquids as equivalent to oil is doubly misleading.

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The second question media outlets could have asked is whether natural gas plant liquids can be sold as oil on the world market. The answer is a resounding 'no.' In fact, major exchanges accept neither natural gas plant liquids nor lease condensates as satisfactory delivery for crude oil. And, if we subtract lease condensate from each country's total, U.S. production will actually look relatively lower. It turns out that U.S. wells now produce a higher proportion of condensate as a result of growth in oil extraction from shale deposits (which tend to be rich in these condensates).

All of this leads my friend and colleague, Texas oilman Jeffrey Brown, to point out the following: If what you're selling cannot be sold on the world market as crude oil, then it's not crude oil. The implications are fairly obvious: The world has substantially lower oil production than widely believed, and growth in world oil supplies has slowed considerably in the last several years. Using the BP definition of oil, world production in 2014 was 88.7 mbpd. Using the stricter definition of crude oil including lease condensate, the number was 77.8 mbpd. Big difference!

Growth in oil supplies according to BP from 2005 through 2014 was 8.2 percent.

Using the stricter definition, growth was 5.4 percent, which is down from 15.7 percent for the previous nine-year period. (Worldwide numbers for crude oil excluding lease condensate are not available.)

So, BP and the oil industry have one definition when referring to oil supply--one designed to create a rosy picture of the future--but must bow to the market's definition when they actually want to sell oil to somebody. Who would you accept as the better authority on what constitutes oil, the buyers or the sellers?

All this is not to deny that oil production in the United States is rising, and has been doing so rather quickly. But, this must be put in context.

First, although the United States produced 9.6 mbpd of oil proper for the week ending June 5 according the U.S. Energy Information Administration (EIA), it had net imports of 6.2 mbpd. (For comparison, OPEC reports that Saudi Arabian oil

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production as of May 15 was 10.3 mbpd.)

Second, even the ever optimistic EIA expects U.S. oil production (crude oil including lease condensate) to decline after 2020. This implies that the United States will continue to be a large importer of crude oil. One independent analysis based on actual well performance suggests that the EIA projections are probably correct in the short run, but far too optimistic in the long run. American production may not remain near current levels for very long and, in fact, may drop considerably in the next two decades.

It's difficult to call out the venerable BP Statistical Review of World Energy, especially when one considers that BP does this as a service to the world. The company spends money gathering and organizing data on all kinds of energy and makes that data freely available to anyone who wants it. On the other hand, we should recognize that BP has substantial U.S. investments, and this may color its view on the future of U.S. oil production. Downbeat assessments don't do anything for stock prices.

Perhaps the most important thing to remember about oil supplies is that oil is a worldwide market. It is worldwide supply that matters, and supply from every country needs to be seen in this context.

The current slump in oil prices has many believing that supply will continue to be ample in the long run. But, we ought to consider that the rate of oil production in the United States may be nearing its peak and that all of the production growth in oil worldwide since 2005 has come from just two countries, the United States and Canada. That should make us more cautious about projecting the triumphant pronouncements of one of the world's largest oil companies very far into the future.

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BP Data Suggests We Are Reaching Peak Energy Demand Written by Gail Tverberg from Our Finite World Some people talk about peak energy (or oil) supply. They expect high prices and more demand than supply. Other people talk about energy demand hitting a peak many years from now, perhaps when most of us have electric cars.

Neither of these views is correct. The real situation is that we right now seem to be reaching peak energy demand through low commodity prices. I see evidence of this in the historical energy data recently updated by BP (BP Statistical Review of World Energy 2015). Of course, growth in world energy consumption is clearly slowing. In fact, growth in energy consumption was only 0.9% in 2014. This is far below the 2.3% growth we would expect, based on recent past patterns. In fact, energy consumption in 2012 and 2013 also grew at lower than the expected 2.3% growth rate (2012 - 1.4%; 2013 - 1.8%).

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Recently, I wrote that economic growth eventually runs into limits. The symptoms we should expect are similar to the patterns we have been seeing recently (Why We Have an Oversupply of Almost Everything (Oil, labor, capital, etc.)). It seems to me that the patterns in BP's new data are also of the kind that we would expect to be seeing, if we are hitting limits that are causing low commodity prices.

One of our underlying problems is that energy costs that have risen faster than most worker's wages since 2000. Another underlying problem has to do with globalization.

Globalization provides a temporary benefit. In the last 20 years, we greatly ramped up globalization, but we are now losing the temporary benefit globalization brings.

We find we again need to deal with the limits of a finite world and the constraints such a world places on growth.

Energy Consumption is Slowing in Many Parts of the World Many parts of the world are seeing slowing growth in energy consumption. One major example is China.

Based on recent patterns in China, we would expect fuel consumption to be

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increasing by about 7.5% per year. Instead, energy consumption has slowed, with growth amounting to 4.3% in 2012; 3.7% in 2013; and 2.6% in 2014. If China was recently the growth engine of the world, it is now sputtering.

Part of China's problem is that some of the would-be buyers of its products are not growing. Europe is a well-known example of an area with economic problems. Its consumption of energy products has been slumping since 2006.

I have used the same scale (maximum = 3.5 billion metric tons of oil equivalent) on Figure 3 as I used on Figure 2 so that readers can easily compare the European's Union's energy consumption to that of China. When China was added to the World Trade Organization in December 2011, it used only about 60% as much energy as the European Union. In 2014, it used close to twice as much energy (1.85 times as much) as the European Union.

Another area with slumping energy demand is Japan. It consumption has been slumping since 2005. It was already well into a slump before its nuclear problems added to its other problems.

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A third area with slumping demand is the Former Soviet Union (FSU). The two major countries within tithe FSU with slumping demand are Russia and Ukraine.

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Of course, some of the recent slumping demand of Ukraine and Russia are intended-this is what US sanctions are about. Also, low oil prices hurt the buying power of Russia. This also contributes to its declining demand, and thus its consumption.

The United States is often portrayed as the bright ray of sunshine in a world with problems. Its energy consumption is not growing very briskly either.

To a significant extent, the US's slowing energy consumption is intended-more fuelefficient cars, more fuel efficient lighting, and better insulation. But part of this reduction in the growth in energy consumption comes from outsourcing a portion of manufacturing to countries around the world, including China. Regardless of cause, and whether the result was intentional or not, the United States' consumption is not growing very briskly. Figure 6 shows a small uptick in the US's energy consumption since 2012. This doesn't do much to offset slowing growth or outright declines in many other countries around the world.

Slowing Growth in Demand for Almost All Fuels We can also look at world energy consumption by type of energy product. Here we

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find that growth in consumption slowed in 2014 for nearly all types of energy.

Looking at oil separately (Figure 8), the data indicates that for the world in total, oil consumption grew by 0.8% in 2014. This is lower than in the previous three years (1.1%, 1.2%, and 1.1% growth rates).

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If oil producers had planned for 2014 oil consumption based on the recent past growth in oil consumption growth, they would have overshot by about 1,484 million tons of oil equivalent (MTOE), or about 324,000 barrels per day. If this entire drop in oil consumption came in the second half of 2014, the overshoot would have been about 648,000 barrels per day during that period. Thus, the mismatch we are have recently been seeing between oil consumption and supply appears to be partly related to falling demand, based on BP's data.

(Note: The 'oil' being discussed is inclusive of biofuels and natural gas liquids. I am using MTOE because MTOE puts all fuels on an energy equivalent basis. A barrel is a volume measure. Growth in barrels will be slightly different from that in MTOE because of the changing mix of liquid fuels.)

We can also look at oil consumption for the EU, EU, and Japan, compared to all of the rest of the world.

While the rest of the world is still increasing its growth in oil consumption, its rate of increase is falling-from 2.3% in 2012, to 1.6% in 2013, to 1.3% in 2014.

Figure 10 showing world coal consumption is truly amazing. Huge growth in coal use

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took place as globalization spread. Carbon taxes in some countries (but not others) further tended to push manufacturing to coal-intensive manufacturing locations, such as China and India.

Looking at the two parts of the world separately (Figure 11), we see that in the last three years, growth in coal consumption outside of US, EU, and Japan, has tapered down. This is similar to the result for world consumption of coal in total (Figure 10).

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Another way of looking at fuels is in a chart that compares consumption of the various fuels side by side (Figure 12).

Consumption of oil, coal and natural gas are all moving on tracks that are in some sense parallel. In fact, coal and natural gas consumption have recently tapered more than oil consumption. World oil consumption grew by 0.8% in 2014; coal and natural gas consumption each grew by 0.4% in 2014.

The other three fuels are smaller. Hydroelectric had relatively slow growth in 2014.

Its growth was only 2.0%, compared to a recent average of as much as 3.5%. Even with this slow growth, it raised hydroelectric energy consumption to 6.8% of world energy supply.

Nuclear electricity grew by 1.8%. This is actually a fairly large percentage gain compared to the recent shrinkage that has been taking place.

Other renewables continued to grow, but not as rapidly as in the past. The growth rate of this grouping was 12.0%, (compared to 22.4% in 2011, 18.1% in 2012, 16.5% in 2013). With the falling percentage growth rate, growth is more or less 'linear'-

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similar amounts were added each year, rather than similar percentages. With recent growth, other renewables amounted to 2.5% of total world energy consumption in 2014.

Falling Consumption Is What We Would Expect with Lower Inflation-Adjusted Prices People buy goods that they want or need, with one caveat: they don't buy what they cannot afford. To a significant extent affordability is based on wages (or income levels for governments or businesses). It can also reflect the availability of credit.

We know that commodity prices of many kinds (energy, food, metals of many kinds) have been have generally been falling, on an inflation adjusted basis, for the past four years. Figure 13 shows a graph prepared by the International Monetary Fund of trends in commodity prices.

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It stands to reason that if prices of commodities are low, while the general trend in the cost of producing these commodities is upward, there will be erosion in the amount of these products that can be purchased. (This occurs because prices are falling relative to the cost of producing the goods.) If, prior to the drop in prices, consumption of the commodity had been growing rapidly, lower prices are likely to lead to a slower rate of consumption growth. If prices drop further or stay depressed, an absolute drop in consumption may occur.

It seems to me that the lower commodity prices we have been seeing over the past four years (with a recent sharper drop for oil), likely reflect an affordability problem.

This affordability problem arises because for most people, wages did not rise when energy prices rose, and the prices of commodities in general rose in the early 2000s.

For a while, the lack of affordability could be masked with a variety of programs: economic stimulus, increasing debt and Quantitative Easing. Eventually these programs reach their limits, and prices begin falling in inflation-adjusted terms. Now we are at a point where prices of oil, coal, natural gas, and uranium are all low in inflation-adjusted terms, discouraging further investment.

Commodity Exporters-Will They Be Next to Be Hit with Lower Consumption?

If the price of a commodity, say oil, is low, this is a problem for a country that exports the commodity. The big issue is likely to be tax revenue. Governments very often get a major share of their tax revenue from taxing the profits of the companies that sell the commodities, such as oil. If the price of oil, or other commodity that is exported drops, then it will be difficult for the government to collect enough tax revenue. There may be other effects as well. The company producing the commodity may cut back its production. If this happens, the exporting country is faced with another problemlaid-off workers without jobs. This adds a second need for revenue: to pay benefits to laid-off workers.

Many oil exporters currently subsidize energy and food products for their citizens. If tax revenue is low, the amount of these subsidies is likely to be reduced. With lower subsidies, citizens will buy less, reducing world demand. This reduction in demand will tend to reduce world oil (or other commodity) prices.

Even if subsidies are not involved, lower tax revenue will very often affect the projects an oil exporter can undertake. These projects might include building roads,

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schools, or hospitals. With fewer projects, world demand for oil and other commodities tends to drop.

The concern I have now is that with low oil prices, and low prices of other commodities, a number of countries will have to cut back their programs, in order to balance government budgets. If this happens, the effect on the world economy could be quite large. To get an idea how large it might be, let's look again at Figure 1, recopied below.

Notice that the three 'layers' in the middle are all countries whose economies are fairly closely tied to commodity exports. Arguably I could have included more countries in this category-for example, other OPEC countries could be included in this grouping. These countries are now in the 'Rest of the World' category. Adding more countries to this category would make the portion of world consumption tied to countries depending on commodity exports even greater.

My concern is that low commodity prices will prove to be self-perpetuating, because low commodity prices will adversely affect commodity exporters. As these countries

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try to fix their own problems, their own demand for commodities will drop, and this will affect world commodity prices. The total amount of commodities used by exporters is quite large. It is even larger when oil is considered by itself (see Figure 8 above).

In my view, the collapse of the Soviet Union in 1991 occurred indirectly as a result of low oil prices in the late 1980s. A person can see from Figure 1 how much the energy consumption of the Former Soviet Union fell after 1991. Of course, in such a situation exports may fall more than consumption, leading to a rise in oil prices.

Ultimately, the issue becomes whether a world economy can adapt to falling oil supply, caused by the collapse of some oil exporters.

Our Economy Has No Reverse Gear None of the issues I raise would be a problem, if our economy had a reverse gear-in other words, if it could shrink as well as grow. There are a number of things that go wrong if an economy tries to shrink: Businesses find themselves with more factories than they need. They need to lay off workers and sell buildings. Profits are likely to fall. Loan covenants may be breached. There is little incentive to invest in new factories or stores.

There are fewer jobs available, in comparison to the number of available workers.

Many drop out of the labor force or become unemployed. Wages of non-elite workers tend to stagnate, reflecting the oversupply situation.

The government finds it necessary to pay more benefits to the unemployed. At the same time, the government's ability to collect taxes falls, because of the poor condition of businesses and workers.

Businesses in poor financial condition and workers who have been laid off tend to default on loans. This tends to put banks into poor financial condition.

The number of elderly and disabled tends to grow, even as the working population stagnates or falls, making the funding of pensions increasingly difficult.

Resale prices of homes tend to drop because there are not enough buyers.

Many have focused on a single problem area-for example, fractional reserve banking-as being the problem preventing the economy from shrinking. It seems to me that this is not really the issue. The problem is much more fundamental. We live in a networked economy; a networked economy has only two directions available to it: (1) growth and (2) recession, which can lead to collapse.

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Conclusion What we seem to be seeing is an end to the boost that globalization gave to the world economy. Thus, world economic growth is slowing, and because of this slowed economic growth, demand for energy products is slowing. This globalization was encouraged by the Kyoto Protocol (1997). The protocol aimed to reduce carbon emissions, but because it inadvertently encouraged globalization, it tended to have the opposite effect. Adding China to the World Trade Organization in 2001 further encouraged globalization. CO2 emissions tended to grow more rapidly after those dates.

Now growth in fuel use is slowing around the world. Virtually all types of fuel are affected, as are many parts of the world. The slowing growth is associated with low fuel prices, and thus slowing demand for fuel. This is what we would expect, if the world is running into affordability problems, ultimately related to fuel prices rising faster than wages.

Globalization brings huge advantages, in the form of access to cheap energy products still in the ground. From the point of view of businesses, there is also the possibility of access to cheap labor and access to new markets for selling their goods. For long-industrialized countries, globalization also represents a workaround to inadequate local energy supplies.

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The one problem with globalization is that it is not a permanent solution. This happens for several reasons: A great deal of debt is needed for the new operations. At some point, this debt starts reaching limits.

Diminishing returns leads to higher cost of energy products. For example, later coal may need to come from more distant locations, adding to costs.

Wages in the newly globalized area tend to rise, negating some of the initial benefit of low wages.

Wages of workers in the area developed prior to globalization tend to fall because of competition with workers from parts of the world getting lower pay.

Pollution becomes an increasing problem in the newly globalized part of the world.

China is especially concerned about this problem.

Eventually, more than enough factory space is built, and more than enough housing is built.

Demand for energy products (in terms of what workers around the world can afford) cannot keep up with production, in part because wages of many workers lag thanks to competition with low-paid workers in less-advanced countries.

It seems to me that we are reaching the limits of globalization now. This is why prices of commodities have fallen. With falling prices comes lower total consumption.

Many economies are gradually moving into recession-this is what the low prices and falling rates of energy growth really mean.

It is quite possible that at some point in the not too distant future, demand (and prices) will fall further. We then will be dealing with severe worldwide recession.

In my view, low prices and low demand for commodities are what we should expect, as we reach limits of a finite world. There is widespread belief that as we reach limits, prices will rise, and energy products will become scarce. I don't think that this combination can happen for very long in a networked economy. High energy prices tend to lead to recession, bringing down prices. Low wages and slow growth in debt also tend to bring down prices. A networked economy can work in ways that does not match our intuition; this is why many researchers fail to see understand the nature of the problem we are facing.

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The Texas Natgas Massacre Written by Keith Schaefer from Oil & Gas Investments Bulletin Natural gas production in Texas in Q1 2015 declined 1.5 billion cubic feet per day (bcf/d), results from the Texas Railroad Commission (RRC) show. That's a 5.5% decline on the 22 bcf/d Texas produces-a full one third of all natural gas production in the USA. Conservatively, I expect a 15% decline in the Lone Star state for all of 2015. That would result in a loss of more than 3 bcf/d.

In fact, that's very conservative as the collapse in Texas rig count from 891 a year ago to only 373 for the week ending 5/15/2015-a 58% drop-is having a profound impact on gas production in the state.

The combination of thousands of wells drilled in the past few years that are still in the high-decline portion of their lifecycle and such a large reduction in drilling activity indicates that Texas is on track for an epic decline in gas production in 2015.

To be sure, the reduced output is partly to blame on slumping activity levels.

Investors should remember that the 1.5 bcf/d decline in Q1 2015 occurred with an average of 647 land rigs running in the state. As of May 15, 2015 there were only 372 rigs working in the state. (Source: Baker Hughes) But there's more. I'll explain how wells are now getting lower IP rates than before, and data that clearly shows new wells are stealing production from older wells (The industry says that when that happens, wells are communicating.)

Now, considering there is usually a six-month lag between falling rig counts and declining production, the drop in Texas in the first three months of 2015 is remarkable. More importantly, the quick drop in Q1 indicates the second half of year is likely to see a more pronounced fall off in production barring a quick rebound in activity.

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Below is a table tallying up the declines by major Texas plays in Q1 along with conventional production as well as my projected decline for the entire year: Play Name Decline in Q1 2015Projected 2015 Decline Barnett .4 bcf/d 1 bcf/d Eagle Ford .33 bcf/d .75 bcf/d Permian .2 bcf/d .4 bcf/d Granite Wash.25 bcf/d .5 bcf/d Haynesville 0 0 Conventional .3 bcf/d .6 bcf/d Total

1.5 bcf/d

3.25 bcf/d

Now, let's look at what the raw data is showing for each of the major gas producing basins in Texas, and what recent developments in Texas tell us about production for the rest of the US.

The Barnett Shale The Barnett is the oldest modern shale play in the US with over 20,000 wells drilled into it over the past 15 years and has more than 16 Trillion Cubic Feet (TCF) of historical production. Many analysts and operators have long professed that Barnett wells will produce for 40 years and have terminal decline rates in the 5 to 7 % range.

Devon Energy told me a few years ago that their engineers have estimated that the company's wells in the play have a 6 % terminal decline rate. However, history is indicating a much steeper rate. Given that Devon is still the largest operator in the Barnett, the company's estimate of terminal decline appears to be grossly understated considering the large fall in production in first 3 months of 2015.

The below graphic from the RRC shows a 0.4 bcf or 9 % drop off in natural gas production YoY in the Barnett in the first 3 months of 2015:

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One would expect that the average Barnett well decline rate would now be in the high single digits given that the average age of each well is more than 5 years old.

However, this has not been the case. The Barnett shale is on pace to decline an incredible 20 % in 2015 despite the drilling of new wells. Put differently, the Barnett is on track to see production fall from an average of 4.9 bcf/d in 2014 to only 3.9 bcf/d this year.

The reason for the drop-off in Barnett production (and other shale gas plays) is quite simple; despite improvements in technology, the average well is becoming less productive (i.e. lower initial production (IP) rates and has a lower estimated ultimate recoveries (EURs)).

There are two main reasons for lower well productivity: 1) declining rock quality 2) and interference with neighboring wells. It has been well documented how the best wells come from small geographic areas commonly known as 'sweet spots' and the further away from these areas the less productive wells become.

In the Barnett, the average new well in 2014 came online with an IP rate of less than 1 million cubic feet per day, down 20 % over the previous few years (Source: Drilling Deeper, David Hughes), and will recover less than 1 bcf in its lifetime. My estimate of 1 bcf of lifetime production is due to the .8 bcf the average well has recovered in the first five years of life and a realistic life expectancy of between 7 to 8 years. While many analysts predict the average Barnett well will produce for multiple decades, the facts say otherwise. More than 4,000 (20 %) of Barnett wells are already dead after less than a decade of production indicating a realistic lifespan of less than 10 years.

In fact, very few wells with a production history of ten years are still producing.

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So how drilled out is the sweet spot of the Barnett? Answer: Very. The top three Barnett counties by historical production, Denton, Johnson and Tarrant, (about 75% of the Barnett's historical production) already have more than 6 wells per square mile (640 acres or 5,280 square feet).

With fracture stimulations usually deploying energy in the reservoir at least 500 feet to nearly 1,000 feet in every direction from the wellbore, many wells in these three counties are producing from the same acreage. While communication between wellbores will not always become apparent immediately after a well is drilled, lower than expected lifetime EURs are proof positive that too many are drawing on too few resources.

So what does the path forward for the Barnett look like? With only 5 rigs running in the Barnett for the week ending May 15th, down from 25 a year ago according to Baker Hughes, it is clear we are seeing a permanent wind down of activity in America's oldest modern shale play.

Based on recent new well productivity numbers for the Barnett, approximately 1,200 wells would be needed to keep current production flat in 2015. However, we are miles away from this level of activity. I estimated that the five rigs currently running in the play will drill between 50 and 100 new wells this year.

In fact, production in the Barnett is declining so much faster than expectations that producers are now having to pay what's called 'shortfall fees' to pipeline operators.

That means they pay for the space on the pipeline for their gas-even when the gas just isn't there.

One of the Barnett's biggest operators, Chesapeake Energy (CHK-NYSE), warned investors on page 58 of its Q1 10Q regarding its outlook on Barnett production, 'We anticipate incurring significant shortfall fees in the 2015 fourth quarter based on current production estimates.'

While CHK's finances are in great difficulty due to its large interest and preferred dividend obligations and falling revenue, its remaining locations in the Barnett must be extremely uneconomic for it to pay 'significant shortfall fees' for pipeline capacity it has already contracted for. Over the next three years I expect Barnett production to

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decline from approximately 4.5 bcf/d currently to 2.5 bcf/d given the advanced maturity of the play and the actions of its biggest operators.

The Eagle Ford Shale After 5 years of halcyon growth, Eagle Ford natural gas production has rolled over and is now in rapid descent. As you can see in the graphic below, taken from the RRC website, Eagle Ford gas production has fallen .33 bcf/d or 7% YoY in just the first three months of 2015:

I estimate that the huge decline in drilling in the Eagle Ford (the rig count has fallen to 108 from 219 a year ago) combined with very large well decline rates will cause production to drop approximately 0.75 bcf/d in 2015. Even though the Eagle Ford has 21 times the number of rigs running as the Barnett, it will see a similar natural gas production decline.

As drilling has moved to the oiliest part of the play (such as Karnes County) as operators high grade their drilling prospects, each new well drilled this year will produce less gas than a new well drilled last year. Considering the annual field decline rate for the gas portion of the play (how much production would drop if no new wells were drilled) is 47 % (Source) and the 3-year decline rate is 80 %,

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production from the Eagle Ford production is likely to continue to fall for several years barring an immediate and significant pick up in drilling activity.

The Permian Basin Times have changed drastically in the Permian Basin over the past year. The rig count has collapsed more than 60 % and shows no sign of rebounding without significantly higher prices.

While oil production in the Texas Permian has fallen only 1 % in the first three months of 2015-natural gas production has declined 5 %. As you can see from the below table, gas production in the Texas Permian was down an average of .2 bcf/d in the first three months of 2015 compared to the annual average of 2014:

Though gas production in the Texas Permian is down only .2 bcf/d in the first three months of the year, I estimate there will be a drop of .4 bcf/d for the entire year given that associated gas production typically has very steep decline rates.

The Granite Wash While the Granite Wash play of North Texas and Oklahoma does not get as much attention as shale plays, it has been an important contributor to both US oil and gas

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supply in recent years.

The downturn in prices has cut drilling in the play from 62 rigs a year ago to only 16 today and as you would expect, production in the Texas portion of the play has rolled over. As you can see from the below graphic, natural gas production is already down .25 bcf/d, or 26 %, in the first three months of 2015 and now at levels last seen in 2008.

Texas Granite Wash production appears on track for a .5 bcf/d fall in 2015 given the lack of drilling.

Texas Conventional Production Texas still produces between 6 and 8 bcf/d of conventional natural gas depending on how you classify a portion of the gas production from the Permian Basin.

Given that very little drilling has taken place in the past six months on conventional prospects in Texas or anywhere else in the country, I estimate that conventional production in the state has fallen .3 bcf in the first quarter of 2015 and is on track to fall .6 bcf/d for the year. For example, one of the largest areas of conventional production in the state is in south Texas where operators have been producing from

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the Frio and Vicksburg formations for decades. This area has very high decline rates and has seen limited drilling in recent years due to low prices and its advanced maturity.

What the Drop in Texas Production Means for Rest of US With Texas producing about a third of all natural gas produced in the US on an annual basis from a variety of different formations, it is an excellent proxy for the US industry as a whole.

For example, though other states such as New Mexico and Oklahoma did not experience the drilling boom to the same degree as Texas, and each state has seen its rig count fall substantially over the past 12 months.

New Mexico's rig count has gone from 89 to 44 in a year-a 50 % drop-while Oklahoma's has fallen from 195 a year ago to 103 recently-a 47 % drop.

Overall, investors can reasonably expect a material drop in natural gas production in every gas producing play in America with the exception of the Marcellus and Utica where production looks to have flattened out in Q1 2015.

In other words, with US natural gas production in decline and activity levels at multiyear lows at the same time demand continues to ramp up, prices should move materially higher during the balance of the year.

Editor's Note Higher natural gas prices will first benefit the lowest cost producers. My favourite junior producer already has a huge play where the wells payout in just 12 months at current prices. That's unheard of! It gives investors a free call on natural gas prices rising-and one of my Top Picks for the second half of 2015. Click here to access the name, ticker, and full report on this low cost producer.

-Keith

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The energy revolution will not be televised Written by Kurt Cobb from Resource Insights Three recent news items remind us that energy transitions take time, a lot of time-far too much time to be shrunk down into a television special, a few talking points, or the next big energy idea.

For example, the complex management task of putting together the international fusion research project called the International Thermonuclear Experimental Reactor (ITER) has resulted in estimated final costs that have tripled since the 2006 launch.

Fusion could theoretically offer clean and abundant energy almost indefinitely because it uses ubiquitous hydrogen* as fuel and creates helium in the process.

(Water you'll recall is two hydrogen atoms and one oxygen atom and is therefore the most abundant source of hydrogen.)

Despite nine years of effort, ITER has yet to carry out a single experiment; and, the project is not expected to do so for another four years. The idea for such an international project was hatched in 1985 during a summit between U.S. President Ronald Reagan and Mikhail Gorbachev, the leader of what was then still called the Soviet Union. Thirty years later fusion is still receding into the horizon of our energy future.

While there are certainly issues that are managerial rather than merely technical, the technical challenges remain enormous. After decades of experimentation, no laboratory has ever produced more energy from a fusion reaction than it took to create it. One of the most promising tests was performed last year at the National Ignition Facility of the Lawrence Livermore National Laboratory in California. This test produced about 17 kilojoules which was more energy than was used to create the fuel. Problem is, the lasers that initiated the fusion consumed about 2 megajoules or 118 times the amount of energy created by the test.

Keep in mind that this test is still considered one of the most promising. That tells you how far away we are from nuclear fusion as a method for producing electricity.

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Also, just recently the U.S. Environmental Protection Agency (EPA) announced that it will be reducing industry production quotas enacted by Congress for renewable liquid fuels such as ethanol and biodiesel. The EPA has the statutory authority under the 2007 law to adjust such quotas. But few back then anticipated that the quotas would be adjusted downward so severely. The law set the quota at 20.5 billion gallons for 2015. The EPA has reduced the quota to 15 billion gallons. The Bloomberg piece cited above notes that '[t]he agency also set levels for 2014 at the level produced by the industry.'

The nation's corn growers--who provide the feedstock for most of the ethanol produced in the United States--say they may sue because the EPA is ignoring the law. But the corn growers and the nation will likely find out in the course of such a suit that the EPA is merely bowing to the laws of chemistry and the dictates of economics. The previously hailed quick advances in what is called cellulosic ethanol-which can be made from practically anything containing cellulose such as wood chips and plant waste--have not materialized. A few commercial-sized cellulosic ethanol facilities now exist, but nowhere near the number expected by now back in 2007. And, the jury is out on whether such operations will be viable.

Finally, energy maven Vaclav Smil wrote a piece for Politico discussing the difficulties in making an energy transition from one kind of dominant fuel to another.

Despite all the hype from technology gurus touting an imminent takeover by solar, wind and biofuels, historically such transitions have taken decades. The technologies for energy production are simply not analogous to the technologies behind advances in computer chips.

Inventor and futurist Ray Kurweil's prediction that solar energy will become practically the only source of power in just 16 years illustrates the failure of technology-oriented minds to understand the constraints on energy transitions. He predicts a doubling every two years. That will sound familiar to those in the computer industry where a doubling in the computing power of microchips has occurred about every 18 months.

Energy transitions, however, move slowly--egregiously slowly--compared to advances in such fields as biotechnology and integrated circuits. Smil recounts the climb from 5 percent market share to 25 percent market share for oil and natural gas: After crude oil claimed 5 percent of the total American energy supply in 1905, it took

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28 years to reach 25 percent, and the rise was even slower for natural gas, 33 years from 1924 to 1957. Today, despite the attention lavished on solar cells and wind, those up-and-coming renewables have yet to reach even the 5 percent mark.

Globally, energy transitions have been even slower than in the U.S., with crude oil taking 40 years to go from 5 percent to 25 percent of the global primary energy supply, and it looks as though natural gas will take 60 years to do the same.

On a percentage basis renewables are growing rapidly, but from a very small base.

Smil comments: Electricity generation by new renewables has been growing fastest, but it is far from taking over: at 7 percent in 2014 it was still only about a third of all electricity generated by the aging nuclear stations. And because electricity is only a part of the overall energy supply, the contribution of new renewables (wind and solar) to the country's total primary energy consumption (including all industrial and transportation fuels) remains very modest: it rose from just 0.1 percent in the year 2000 to 1 percent in 2010 and to 2.2 percent in 2014.

What those who map the rapid increase in computer power onto our current energy transition miss is the infrastructure problem. Consumers and businesses seem to have little concern over junking computers that are only a few years old in favor of the newest models. The turnover in the computer infrastructure is quite rapid.

Not so with energy infrastructure. Power plants are made to last decades. And, they are often upgraded rather than replaced. Currently, fossil fuels produce the bulk of the world's electricity, some 67 percent in 2012, according to the latest figures available from the U.S. Energy Information Administration. Nuclear power plants produce almost 11 percent. Hydroelectric produces almost 17 percent. All other renewable electricity production accounts for just under 5 percent. Very little of the existing electricity generation infrastructure is coming down soon.

What this means is that far from replacing existing fossil fuel generating plants, renewables are simply going to add to total electricity generation as demand grows.

That's a good thing. But renewable energy expansion as it is currently structured is going to do little to reduce greenhouse gases. In fact, in the United States the decline in carbon dioxide emissions from the peak in 2005 to a level 12.8 percent lower in 2012 was due almost entirely to the substitution of natural gas-fired

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electricity generation for coal-fired generation. But emissions resumed their upward march in 2013 and 2014 as the most polluting of the coal-fired plants had already shut down.

As for liquid fuels, decades of trying have only resulted in marginal inroads from nonpetroleum substitutes. Petroleum-based fuels still account for 95 percent of all transportation fuel in the United States as of 2014. World numbers are hard to come by. The World Petroleum Council states that the global share for petroleum in transportation fuels is 80 percent, but cites no source.

So what does all this imply? Is there anything we can do to speed up the transition?

Of course, we could all sit back and simply hope for technical breakthroughs that will make it irresistable--in other words, highly profitable--to adopt low-carbon energy technologies on a massive scale quickly. But, history recommends against this passive course.

While some decry subsidies given to wind, solar and biomass technologies, there is an almost immutable law of economics which justifies these, to wit: If you subsidize something, you will get more of it. And, that's what policymakers behind the subsidies want. What the critics of such subsidies fail to note is that governments worldwide currently pay out $550 billion in subsidies annually for the production of oil, coal, and natural gas, more than four times the subsidies for renewables including wind, solar and biomass--which again proves that when you subsidize something, you get more of it. And, we have gotten a lot of fossil fuel production.

Why not just take that $550 billion and devote it to research on and production and deployment of renewable energy? That would be okay. But a much better use of that money would be spending it on known technologies that drastically REDUCE our consumption of energy. If, as Vaclav Smil contends, we are in for a long, slow slog on the path to a renewable energy economy, then the course with the least risk and probably the greatest return would be to reduce our energy use.

We have the technology to reduce building heating and cooling energy use by 80 to 90 percent. It's called passive house technology though it is now also being applied to apartment, commercial and industrial buildings. The cost for this in new buildings is about 15 percent more and typically lower. The energy savings over the life of building far outweigh the initial cost. We still need to figure out how to do costeffective retrofits for similar deep energy reductions in existing buildings. But there

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are many smaller cost-effective steps currently available to homeowners and businesses. Some of these are already being subsidized, and subsidizing them more would be a good idea.

When it comes to transportation, the advent of ridesharing and car-sharing is rapidly changing the public's view about automobiles. No longer do people need to own a car so much as have access to it. Combine this with an expansion of hybrid vehicles and efficiencies can quickly build in the transportation sector.

There is much more that we can do and that we know how to do to reduce energy use, especially energy produced by fossil fuels. But a corollary to the above mentioned 'law' of economics concerning subsidies is one concerning taxes, namely, if you want less of something, tax it. A high and rising carbon tax would go a long way toward speeding the energy transition. It would incentivize households, businesses, nonprofit organizations and government, that is, everybody, to reduce fossil fuel use and to choose renewables instead.

Even with these efforts our current and increasingly urgent energy transition would still take a long time. But we would have more assurance of a positive outcome with regard to climate change if we choose now to start on a course toward dramatic reductions in energy use. And, coincidentally, this would make it much easer for renewable energy to replace fossil fuels since we would ultimately need far less energy production to replace them. The renewable energy economy could then arrive sooner and with far less direct investment than previously imagined. *Typically, fusion reactors use very specific forms of hydrogen such as deuterium which has a neutron in addition to hydrogen's proton and constitutes only one in 6,420 atoms of hydrogen found on earth. But that's still a huge amount. Tritium, a form of hydrogen with two neutrons, is produced inside reactors.

While radioactive, it is benign enough to use in making glow-in-the-dark watch hands.

P.S. The title of this piece is an allusion to the song The Revolution Will Not Be Televised written and recorded by Gil Scott-Heron in 1970.

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Nuclear Future: How Japan's Oil Consumption is changing Written by Jeff Nevil from Jeff Nevil The signs that Japan is moving toward an ever-idealistic oil free future has become more of a reality in the past year. Japan's distrustful nature in regards to nuclear power is well understood, with the 2011 Japanese tsunami causing the failure of a key nuclear facility, which was later revealed to be dangerous in terms of construction. This is, of course, in tandem with the sordid histories of Hiroshima and Nagasaki, highlighting the terrible capabilities of nuclear power.

But as the nation sheds its post-war skin, the Japanese have begun to realise the value of nuclear energy. In the wake and recovery of the Fukushima plant disaster, Japan has slowly begun to return to nuclear energy as its primary source of energy across the country. Most recently, India overtook Japan to become the third largest consumer of oil in the world behind China and the United States. While the International Energy Agency has estimated that Japan's consumption of oil is likely to fall by around 33 percent by approximately 2030.

Japan has not reached anywhere near its peak of 4.2 million barrels per day since 2000. Interestingly, this decline occurred very soon into the post 9/11 world, with oil having a huge leverage and influence on international politics around the time. After vowing to never mobilise a standing army after the Second World War, Japan's only armed military is a dedicated defence force to protect its borders and land. This means that Japan had no means to secure or support post-9/11 conquests for oil in the Middle East. As such, Japan has had to seek alternatives.

It can be said that the drop in Japan's oil consumption has been a long time coming.

The island nation has been relying on nuclear energy heavily for most of the past decade, interrupted only by Fukushima in 2011. Despite the drop, oil will still remain Japan's primary provider of energy for at least another 2 decades, even with an

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average of 2 percent decline year-on-year since 2012.

The current market for oil has also slowed down significantly, still experiencing weak growth and lower prices per barrel. It is also expected by the IEA that the global supply of oil will soon outstrip demand, which will cause further problems in rebalancing the market. This is in part due to a particularly high period of output in the United States, and at a time when Chinese demand and growth is declining. These factors combined have caused an unstable market for oil, alongside the changes between India and Japan in terms of oil consumption.

The current market position Japan is in should be considered more favourable than India's. Although India is now the fastest growing economy in the world, it relies heavily on imports from China and the USA of oil; these are imports which far exceed its levels of exports. This is likely to generate a massive amount of debt for India at a time when it is combating a slowly increasing fiscal deficit.

The decline in oil consumption also comes at a time when environmentalism in Japan is purported to be flourishing. The surge in Japanese environmentalism has given birth to a number of diverse ecological organisations, each of which has mobilised a large amount of public support. These changing attitudes to energy consumption could be having a larger impact of Japanese oil consumption than previously anticipated, as well as having an effect on a logistical scale and influencing political thought and practice, including mobilising the argument for a more robust carbon and emissions monitoring.

Theorised in a study by Japanese sociologist Hisayoshi Mitsuda, he states that Japanese environmentalism is a result of increasing and widespread affluence in Japanese society post WWII. The drop in Japanese oil consumption could, in some ways, represent the increasing affluence from Japan's legislative forces in terms of ecological action.

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Palantir Forward Curve - 2015 June Written by Bowen Gao from Palantir Global Economy The oil price recovery slowed down this month after three consecutive months of steady price increases. As of June 15, WTI front month futures price settled at $59.53 USD/bbl which is little changed from the May average. European Brent front month future's price settled at $60.99 USD/bbl which is $3 USD/bbl lower than the May average. Overall, the moving average prices of WTI and Brent have remained flat compared to May 2015. The global oil market seems to be stabilizing with a long term direction of gradual price increases.

Oil Supply and Demand Oil supply has exceeded demand worldwide for the past eighteen months. This is the longest period of oversupply since the U.S. Energy Information Administration (EIA) started tracking global monthly consumption in 2000. Currently, the surplus is approximately 3 million barrels per day with the EIA forecasting that this oil oversupply will continue throughout the rest of this year and 2016. The EIA's forecast is also supported by the recent OPEC meeting on June 5th, 2015. OPEC declared that they will maintain their production level at 30 million barrels per day and stated their belief that this level is suitable for both producers and consumers. As we explored in the May 2015 Palantir Forward Curve, U.S. oil production has levelled off and is showing signs of decline. It seems that U.S. oil production reductions will need to lead the global market to equilibrium.

Source: EIA

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The $3 USD/bbl drop for the Brent oil price in June might be partly due to speculation that sanctions on Iran will be alleviated soon. The U.S., France, Great Britain, Russia, Germany and China are negotiating with Iran to reach an agreement on Iran's nuclear program and associated economic sanctions. A group mandated deadline of June 30 is fast approaching and optimism continues to surround the negotiations. The EIA previously estimated that Iran could boost exports by 700,000 barrels per day within several months once the sanctions are removed. This extra supply would put strong downward pressure on global oil prices.

Price Forecast The Palantir Forward Curve for June 2015 depicts that a tepid recovery is underway.

We still observe a wide spread between upper and lower limits which reflects the high level of uncertainty in the industry. We look forward to the next edition of the Palantir Forward Curve to see if Iran negotiations have progressed further and if U.S. oil production reverses course towards decline.

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OPEC's Dilemma: The Long View Written by Art Berman from The Petroleum Truth Report It is unlikely that OPEC will cut production at its June 5, 2015 meeting in Vienna.

Assuming no cut, oil prices should continue the descent that began in early May (Figure 1). Prices may fall into the $50+ per barrel range since there is no tangible reason for their rise from January's $46 low.

Figure 1. Brent crude oil spot price May 1- June 1, 2015: Source: EIA and Labyrinth Consulting Services, Inc. It is remotely possible that OPEC may decide to cut production because many members are strapped for cash but I suspect that Saudi Arabia's longer view of demand and market share will dominate the decision and that there will be no cut.

World oil production has undergone a structural shift from supply dominated by relatively inexpensive conventional production to increasingly more supply coming

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from expensive deep-water and unconventional production. Most conventional oil is located in the Arabian, Siberian and North Caspian basins while deep-water and unconventional production is focused along the margins of the Atlantic Ocean and in North America.

This shift is at the root of the current price conflict between OPEC and North American oil producers. Since 2008, OPEC liquids production has been fairly flat until mid-2014 (Figure 2). Non-OPEC production outside of North America has been flat. Most production growth has occurred in the U.S. and Canada but it is not only from tight oil.

Figure 2. World liquids production since 2008 showing OPEC, non-OPEC minus the U.S. and Canada, and the U.S. and Canada. Source: EIA and Labyrinth Consulting Services, Inc. The competition for OPEC market share is from Canadian oil sands, Gulf of Mexico deep-water and tight oil production. U.S. plus Canadian production has increased 6.2 million barrels per day (mmbpd) since January 2008. OPEC production has increased 2 mmbpd over that period with 1.3 mmbpd (65%) of that increase since June 2014.

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Lower oil prices over the past year (Figure 3) have not resulted yet in any observable decrease in North American production. Higher prices over the last few months further complicate the situation for OPEC. The global production surplus has gotten worse, not better, in recent months but prices rose based on sentiment.

Figure 3. Crude oil prices since June 2014. Source: EIA and Labyrinth Consulting Services, Inc. It is true that U.S. production may be falling but a 3-month lag in reporting prevents us from seeing this. It is also true that OPEC may have limited capacity to increase their production further although Middle East rig counts have never been higher.

The only way for OPEC to significantly increase its market share is to undermine North American expensive oil production with low oil prices for at least another 6 months. Unless short-term interests carry the day at OPEC's meeting on Friday, a production cut at this time makes little sense to them.

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Survival of the smartest - investment in innovation continues despite drop in price of oil Written by Douglas Rankin from Marks & Clerk Investment in innovative technologies is vital for the industry to ensure a quick return to prosperity, both in the North East and beyond, say Dr Douglas Rankin and Cameron Walker at Marks & Clerk, intellectual property specialists in the energy sector in Aberdeen.

With Oil & Gas UK predicting investment in the industry will drop to between ÂŁ9.5bn and ÂŁ11.3bn in 2015, many companies in the energy sector are seeking to create efficiencies and cost savings that will allow them to maintain market share and profitability.

Of course, it is a trying time but there remains a sizable amount of reserves in the North Sea and other mature and unconventional fields left to exploit. That is, provided the technology is there to do so in a cost effective manner! Recovering those reserves from any mature or unconventional basin is increasingly challenging but for the companies that continue to invest in innovation the rewards are certainly there, both in the North East and further afield.

We are all very aware that price fluctuation of oil is a common occurrence, and for those of us that have been working in the industry long enough, we understand the impact that significant price volatility can bring. Since 2008, the price of Brent crude has dipped below $50 per barrel and peaked above $100 per barrel more than once.

It would be reasonable to assume that when the oil price dips, so too does the investment in R&D and patent filings in the oil and gas industry - those patent filings providing a good yardstick for any innovation that may be occurring at an R&D level.

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But closer inspection reveals quite a different story. In fact, the data show us that the number of European patent filings in oil and gas related technologies has risen almost every year in the past decade, regardless of the price of oil. The same pattern emerges when we look across the pond at US patent applications. Applications in the US have also seen a steady increase over the last ten years - and in fact some might argue a more significant increase. The importance of this cannot be overstated: while in other sectors investment in innovation ebbs and flows, companies in oil and gas continue to recognise that investment in protecting their intellectual property is vital, not only to their current business activity, but also to future success even under difficult economic conditions.

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The data shown here represents patent filings in a typical oil and gas technology sector. The same trend is true across the spectrum of oil and gas technologies.

There may be an assumption that blanket cuts are being made in response to the falling oil price, but looking at the data it is clear that organisations appear to be maintaining - or indeed expanding - their investment in R&D. Clearly, there is a realisation that optimising and securing protection for current technology is absolutely key to keeping pace with competitors, while at the same time securing and maintaining market position for the 20 year life of a patent.

When we dig down into the data a little deeper, it provides us with an understanding of the biggest patent filers over the last ten years. In both European and US applications, Baker Hughes, Halliburton and Schlumberger come out on top suggesting that it is service companies benefiting the most from a strong patent portfolio. It is interesting to note too, that these three US-headquartered businesses dominate patent filings on both sides of the Atlantic, alluding to the strong culture of intellectual property in the USA. With patent filings from UK-based companies increasing at a rate above average, we should strive to maintain or increase this growth if we want to challenge the success of the patent filers in the US. Investment in intellectual property remains as strong as ever. We believe it is vital that companies avoid short-termism and take the future requirements of the industry into account when restructuring. A culture of innovation has allowed the industry to expand and adapt to overcome the challenges many times in the past. Those companies that develop the future technologies for extracting from challenging reserves, improving efficiencies and margins on existing assets, meeting tighter environmental regulations and even the complexities of decommissioning will be rewarded for their choice.

Quite simply, it is survival of the smartest.

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US futures market rally boosts US and OPEC oil output Written by Paul Hodges from ICIS

Whisper it quietly to your friends in the futures markets, who are convinced oil prices will soon surge higher. We don't want to upset them as they work at their spreadsheets, and send their electronic trades down specially constructed lines at near the speed of light.

But global oil demand growth has already more than halved at just 0.6%/year. And as the latest International Energy Agency monthly report notes (their emphasis): 'OECD industry oil stocks built by a steep 38.0 mb in April, to stand 147 mb above average levels, as refined-product stocks moved to their widest surplus in over four years.'

That really is quite a lot of surplus oil. And the US is doing particularly well at building surplus inventory, as the chart shows. Its levels remain at record highs, with the latest weekly figure 13% higher than a year ago.

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Last week also saw the publication of BP's annual Energy Statistics review. It showed that US oil and gas production remains on a steep upward curve: Oil production has been rising at an annual rate of 9%/year since 2009 (green line) Oil consumption has actually been falling slightly over the same period Vehicle miles travelled per driver is back at 1995 levels, whilst autos have also become more fuel-efficient Meanwhile gas production has been rising 4.5% over the same period (blue line) And it, of course, is still much cheaper than oil on an energy equivalent basis So the trend of fuel conversion from oil to gas remains very attractive, with lower prices and abundant supply There is also the great irony that the flow of funds betting on higher oil prices is actually allowing more oil to be produced, not less. As the Wall Street Journal has reported: 'Wall Street's generous supply of funds to U.S. oil drillers helped create the American energy boom. Now that same access to easy money is keeping them going, despite oil prices that are languishing around $60 a barrel.

'The flow of money into oil has allowed U.S. companies to avoid liquidity problems and kept American crude production from falling sharply. Even though more than half of the rigs that were drilling new wells in September have been banished to storage yards, in mid-May nearly 9.6 million barrels of oil a day were pumped across the

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country, the highest level since 1970, according to the most recent federal data.'

The oil cartel OPEC have similarly been taking advantage of their generosity, producing 1mb/d above its quota in May, and 1.8mb/d about its forecast for demand.

The problem is that a whole generation of oil traders have never known a period when prices were set by markets, not central banks. They therefore assume these vast surpluses can therefore somehow be wished away. But instead, their money is leading to a bigger bust for oil prices down the road, not the boom that they expect.

The amount of cash being poured down holes in the ground to produce more oil is vast - $16.7bn of secondary equity offerings took place in Q1, the highest since the boom began in Q3 2010. And at the same time, the drilling companies are becoming much more efficient in their operations.

In the Eagle Ford field, for example, Statoil has cut its drilling rigs from 3 to 2, but still lifted production by a third. As it notes, 'necessity teaches the naked woman to knit', and in this case the necessity is clear: 'We can't control the commodity prices, but we can control the efficiency of our wells.

The industry has taken this as a wake-up call to get more efficient or get out.'

Investors who continue to ignore these developments will get a wake-up call of their own one day, as the oil price resumes its decline to historical price levels around $30/bbl.

Paul Hodges is Chairman of International eChem, trusted commercial advisers to the global chemical industry.

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Doing the maths on Horse Hill Written by Stephen A. Brown from The Steam Oil Production Company Ltd

All the Horse Hill shares were suspended this morning pending an announcement in relation to Horse Hill.

It's caused lots of speculation and some think there is a big reserve update coming, I don't agree (I was completely wrong - see update below) but it set me wondering what could be going on. It can't be a placing, as so many companies are suspended, and a co-ordinated placing would be tricky; maybe the plan is to list Horse Hill developments, it could be that. Or maybe their partner has done something that they need to tell the markets about.

For though the UK market is all of a lather about Horse Hill, the US market is decidedly unexcited about it. Magellan Petroleum who have 35% of the Horse Hill licence have a market cap of about $18m (according to Bloomberg on the 4th of June 2015) and cash and liquid investments of c. $11m at the end of 2014, oh, and nearly 6 mmboe of Proved (1P) reserves in the US. UK Oil and Gas Investments have about 20% in Horse Hill; and a market cap of ÂŁ44m. They have other things but just for the sake of argument say ÂŁ34m of that is Horse Hill, that would be about $50m for their share of Horse Hill, or $250m for the whole licence, which would mean Magellan's share should be worth $90m. Long Magellan, short UKOG seems like a plan, unless Magellan decide to sell their interest for cash, right now.

That would put a market value on the Horse Hill licence and I am just guessing but I think that market value might be a little less than $250m for the whole licence. That could reset value expectations all round and an announcement on that would need to be carefully managed.

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Alternatively, the plan could be to put Magellan's share of Horse Hill into Horse Hill Developments Ltd and place those shares on AIM, that might get everyone what they want. Or maybe it is something else entirely.

We will soon know.

Update 5th June 2015: UKOG plc published a new estimate of oil in place this morning. The new numbers for oil in place are even bigger than before and this time the company doing the evaluation is an oil industry household name - Schlumberger.

None of that changes the fact that the US market isn't putting a big value on the Horse Hill licence and the UK market is. Something will be done about that soon I would guess.

The new estimate has a bigger headline value but when I zeroed in on the one number that I think could provide the basis for some recoverable reserves from the Kimmeridge, the Lower Limestone 2 in the Middle Kimmeridge sequence from 3082' to 3184', I noticed that Schlumberger had reduced the oil in place in that zone by more than 25% to 9.3 mmbbls.

The Portland sandstone seems to have improved (but I'd like to double check my work on that, when I first did the calculation I thought it had got worse).

My conclusion though, as far as the Kimmeridge play goes, is that the Schlumberger report is more of a downgrade than an upgrade.

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