Andrew Hall On Oil – Price Risks Are Skewed To The Upside – ValueWalk Premium
Andrew Hall Astenbeck Capital Management

Andrew Hall On Oil – Price Risks Are Skewed To The Upside

Andrew Hall letter to the Astenbeck Capital Management investors

H/T Zero Hedge

Dear Investor,

Despite generally supportive economic data, markets were unnerved last month by the sharp selloff in the Chinese stock market and the specter (yet again) of a Greek default. Metals prices were pummeled for no apparent reason and oil drifted to the lower end of its recent trading range. Oil equity prices returned to the lows seen back in March. Current turbulence increases the odds that monetary authorities will continue to be accommodative for longer.

Andrew Hall – Oil

Andrew Hall Astenbeck Capital Management

Despite the lackluster price action, underlying fundamentals for oil continue to improve. It is becoming increasingly clear that the huge oil surplus that most analysts predicted for the first 6 months of 2015 failed to materialize. The current global inventory surplus is probably around 240 million barrels – most of it crude oil. This is about half what was being projected earlier this year. The difference can be attributed primarily to phenomenal demand growth in most markets. Contrary to the counter-intuitive beliefs of the analyst community, oil demand is price elastic. The collapse in prices in Q4 of 2014 has been met by a surge in consumption. Here in the U.S., apparent oil demand so far this year is running 862 kbpd or 4.6 percent above 2014. For the past 4 weeks the year over year growth in apparent oil demand is a whopping 1.34 million bpd or 7.2 percent. Vehicle miles traveled, as reported by the U.S. Department of Transportation, are up 3.9 percent for the year through April. Data published by the Bureau of Economic Analysis shows U.S. gasoline consumption up 5.1 percent in May compared to 2014 – this despite a rise in retail gasoline prices compared to April.

Demand elsewhere in the world – particularly in Asia – is also on a tear. Year over year growth in Chinese oil demand was up 0.6 million bpd in May. Increased gasoline demand driven by strong auto sales – especially for SUVs – accounted for 0.37 million bpd of the growth. Demand growth is also coming from less likely suspects. India has registered strong oil demand growth so far in 2015 and will become an important component of future growth. India has one of the lowest per capita oil demand levels in the world at 1.1 bpy (China’s is 2.96 bpy) but has the potential to accelerate rapidly. This year growth in India’s GDP will almost certainly overtake that of China. Even Europe is registering growth in demand for oil after years of decline. At the start of 2015 the principle forecasting agencies were predicting global oil consumption to grow by around 1 million bpd in 2015. They are finally beginning to revise their projections higher. It would not surprise us if growth this year climbed to close to 2 million bpd when all is said and done.

Low prices really do cure low prices and it’s not just on the demand side of the equation either. Supply will inevitably be affected by the 40 to 50 percent drop in oil prices over the past year – it just takes longer for the impact to manifest itself.

The majority of oil production growth since 2008 can be attributed to the development of U.S. shale oil. Three plays – the Bakken in North Dakota and Montana, Eagle Ford in South Texas and the Permian in West Texas and New Mexico – alone added over 1.2 million bpd of crude oil to global supply last year – almost double the growth in global consumption in 2014. That’s undoubtedly what grabbed Saudi Arabia’s attention and triggered the shift in their policy to one of maintaining production rather than price. This policy shift has been likened by some analysts as a war on U.S. shale oil producers: prices will have to fall to a level to curb its production – or at least the growth in production.

Andrew Hall Astenbeck Capital Management

That is exactly what has happened. Since October of last year rig counts have collapsed with the price of oil. Until now however production has not responded meaningfully to this drop in rig counts. But that is to be expected: on average it takes about 6 months from spudding a well to bringing it into production. Hence, starting about now we can expect to see production roll over and sequentially decline during the second half of 2015.

However, many market analysts argue that because the fall in rig counts can easily be reversed any sustained recovery in oil prices will be limited. The current consensus thinking is that at WTI prices much above $60 – $65 shale oil producers will start bringing rigs back and with it more oil production. That’s because, $65 WTI is deemed to be the current average breakeven price for these plays. Furthermore, these same analysts argue that because productivity of wells and rigs is growing and the cost of drilling and completing wells is falling the WTI price necessary to see an increase in production is also falling over time and that will keep downward pressure on oil prices.

The problem with this analysis is that it assumes that U.S. shale oil producers are the marginal supplier. In the longer term – that is to say over the full investment cycle – they are not, even if they currently have to assume the role of balancing the market.

The reason that it has fallen on the shale oil producers to bring the market into balance is that they can economically modulate their production in the short term. During a temporary period of low prices it makes sense for a shale oil producer to stop drilling and completing new wells. The foregone production from doing so can be recouped as soon as prices recover. Furthermore, because the decline rate of a shale oil well is much greater than that of a non-shale well – typically as high as 60 to 70 percent during its first year of production – any slowdown in the rate at which new wells are completed will quickly translate into a drop in overall production. Non-shale oil producers on the other hand have little option but to continue producing oil all the way down to their cash cost of production which can be very low. That’s because any production they shut in during a period of low prices will not be recovered until the end of the life of the well which typically will be decades in the future. Given the time value of money, this seldom makes sense even though it will result in producing oil at prices that can be substantially below the full cycle cost. That shale oil producers have this operational flexibility to modulate production in response to changing prices does not make them the highest cost or marginal producer over the full cycle. It means rather that they act as an additional level of oil storage capacity. By not producing oil today they are effectively storing oil underground for tomorrow. With Saudi Arabia no longer compensating for temporary imbalances in the market, changes in oil inventories have now become the balancing mechanism. Fluctuations in the rate of shale oil production will effectively be part of that inventory change. So while prices at or above $65 WTI (or $70 Brent) may halt and even reverse the decline in U.S. shale oil production as the more efficient and better positioned shale producers bring back rigs and accelerate well completions, it still leaves a lot of production elsewhere in the world uneconomic.

There is about 72 million bpd of conventional non-shale crude oil and condensate production globally, with about 42 million bpd of this outside of OPEC. Without constant reinvestment this production would decline by about 5 percent per annum on account of reservoir depletion. For example the wells that were producing 60 million bpd of oil back in 1995 produce barely 20 million bpd today assuming an average annual decline rate of 5 percent. That is a loss of 40 million bpd to decline and depletion from the wells that were producing at the beginning of 1995. Similarly, over the next 10 years, 30 million bpd of production will be lost to decline and depletion from the wells that are producing today. In order to offset this loss, about three and a half million bpd of new production annually needs to be brought on stream.

But with $70 Brent much of the conventional non-shale production is uneconomic and the investment needed to achieve this level of new production additions will not be made. The international oil companies, who account for much of this conventional non-shale production outside of OPEC, were failing to grow production even when oil prices averaged over $100 during the past 4 or 5 years – despite a dramatic rise in their capital expenditure.

Andrew Hall Astenbeck Capital Management

Now that these companies are reducing their capital expenditure, production decline is likely to accelerate. New projects in high cost resource plays are being postponed or cancelled. The impact from these decisions will not be felt before 2016 because of the long lead times involved. But that also means such lost production cannot be quickly recouped should the market need it.

If then there is a price war between the Saudis and the U.S. shale producers, the rest of the world’s oil industry will in essence become the collateral damage. It’s worth recalling here that, despite its phenomenal growth during the past five years, U.S. shale oil production still accounts for a relatively modest proportion of the world’s total oil supply – only about 5 percent. There are thus many sizable yet vulnerable bystanders to the current price war. In particular there’s the 42 million bpd of crude and condensate being produced outside of OPEC which is not U.S. shale oil. Much of it is high cost production – certainly higher cost than the most efficient producers in the U.S. shales. With WTI at $65 a significant fraction of this production becomes uneconomic on a full cycle basis.

Andrew Hall Astenbeck Capital Management

This includes deep water off shore production, Arctic oil, tar sands and even more conventional production in mature plays like the North Sea and in countries like China, Colombia, Mexico and Russia. We should also not forget the U.S where more than half the crude production is non-shale and some of which – like the Gulf of Mexico – is relatively high cost production, certainly higher than the best of the shales.

The U.S. shale oil resources which are profitable at $65 WTI simply are not large enough to offset the declining production in these other areas that will result from oil being at that level. At $65 WTI, the economically recoverable oil resource of the lower 48 states in the U.S. is about 70 billion barrels of oil. This would support production of between 9 and 9.5 million bpd – about today’s level. To grow production meaningfully would require prices closer to $80. (Interestingly though, prices much higher than $80 do not significantly increase the economically recoverable resource.)

Andrew Hall Astenbeck Capital Management

Even within OPEC, a lot of production is relatively high cost, if not in a strict economic sense then at least in a practical sense. Virtually all the OPEC countries need oil prices above $70 Brent in order to achieve fiscal breakeven. While Saudi Arabia and its GCC allies can tolerate low prices for a sustained period of time, many other OPEC producers are already struggling at today’s prices. They simply don’t have the funds to invest in their oil resources even if it makes economic sense to do so. Political and social instability also makes it extremely difficult for them to attract outside capital even when they are receptive to it.

In summary, global oil prices will not be capped by the average cost of producing U.S. shale oil. U.S. shale oil production costs lie along a spectrum and while the best producers can make adequate returns at $65 WTI many others cannot. Furthermore, in the longer term a significant proportion of non-U.S. shale oil production require prices higher than $65 WTI to sustain investment. Finally, U.S. shale oil producers cannot produce enough oil at $65 to offset the production decline that would occur elsewhere in the world over time at that price.

So much for the longer term. What about the shorter term?

Oil prices have recovered from the lows seen in January and have been moving in a $2-3 range either side of $60 for WTI and $65 for Brent for the past couple of months. Inventories are very high – especially here in the U.S. – but are starting to plateau. Crude oil inventories in the U.S., which many pundits said would swamp available storage are falling quite rapidly – down 28 million barrels from their peak in April – as refineries increase their runs with the peak demand season for gasoline. They should continue to fall through the summer. While they will probably grow somewhat in the fall as refineries once again go into the maintenance season, thereafter they should resume their decline.

The second half of the year will see a strong seasonal uptick in global oil demand. Oil demand in Q3 and Q4 of 2015 should be some 1.7 and 2.9 million bpd higher respectively than in Q2. Meanwhile year over year U.S. production growth has slowed and production is now starting to decline sequentially. It will continue to decline through the balance of the year (barring significantly higher prices). Non-OPEC production growth elsewhere in the world will also slow through the balance of 2015. By December of 2015 year over year non – OPEC production growth will be a negative 1.7 million bpd compared to a positive 2.7 million bpd in December of 2014.

The combination of a seasonal increase in demand and falling non-OPEC supply should result in a much tighter supply balance going into 2016.

To be sure, OPEC has been ramping up its production. Iraqi production recently achieved a new post-Saddam record high. There is also the prospect of more Iranian oil coming on the market if Iran and the P5+1 countries reach a deal over Iran’s nuclear program and the sanctions on Iran are lifted. Saudi Arabia has been increasing its production to a level it has not sustained for decades. But it is also a fact that Iraq is fighting a civil war which it appears to be losing putting its ability to continue growing production at risk. Furthermore, if a deal is finally concluded with Iran it is unlikely that its oil exports will increase significantly before the end of the year and more probably not until H2 2016. Iran’s capacity to increase exports is in any case probably not much more than 500,000 bpd and quite likely much less.

While Saudi Arabia has raised its production it has in the process reduced its spare capacity concomitantly and is at the moment producing at close to its maximum. The rest of OPEC is already collectively at their full capacity and nominal OPEC spare capacity is at its lowest level since 2008. With little net growth in their aggregate capacity it is unlikely that production from these other OPEC members will register a significant increase. As a consequence such growth that comes from OPEC over the next year or so will have to come from Iraq and Iran.

With global oil consumption rising through the second half of the year at the same time as non-OPEC supply growth is stalling and with OPEC essentially at full capacity, the call on OPEC production will exceed their ability to meet it. This will result in falling global oil inventories during the balance of 2015 and in 2016.

Meanwhile, Saudi Arabia is fighting a proxy war with Iran in neighboring Yemen. It is also facing an existential threat from ISIS which is endeavoring to stir up sectarian unrest in the oil producing east of the country – home to most of Saudi Arabia’s large Shiite minority. Much of the rest of MENA is in turmoil. It’s not unreasonable to say that the geopolitical risks in the major oil exporting region have seldom been higher. Yet oil prices currently have little or no risk premium and are – furthermore – below the longer run marginal cost of production. Because of this and given that the underlying fundamentals continue to improve, price risks are skewed to the upside in our view.

Andrew Hall – Natural Gas

As we expected, natural gas has remained trapped in a range-bound market trading between $2.55 and $2.95. Electric generation demand has been strong due to shuttered coal generation and there has been record heat in the West. But these factors have not been enough to counteract substantial year on year supply growth. Looking ahead, a strong El Niño appears to be developing which would indicate cooler temperatures for the balance of the summer which will likely keep a cap on higher prices. Accordingly, we expect natural gas to continue to trade in a tight range. We will continue to approach the market tactically.

Andrew Hall – Oil – Related Equities

These generally fell towards the lows made in March of this year following the decline in oil prices and pressured by a lack of interest in the sector. However, we continue to believe that the best positioned U.S. domestic oil producers are situated at the lower end of the global cost curve and will benefit as prices return to the global marginal cost of production.

Andrew Hall – PGMs

The supply and demand balances for PGMs remain in a structural deficit for 2015 and beyond. However, a combination of investor liquidation and large scale short selling from CTA and algorithmic trend-based traders overwhelmed the market fundamentals resulting in much lower prices last month.

Both platinum and palladium futures markets have seen record levels of short interest. The latest CFTC Commitment of Traders Report shows 1.5 million ounces of gross shorts in palladium and almost 2 million ounces of gross shorts in platinum. These short positions represent approximately 33 percent and 25 percent of the global mined supply of palladium and platinum respectively in 2015.

At current prices the PGM production basket has fallen deep into the cost curve for platinum (which includes by-product credits from palladium, rhodium and other minor metals). An analysis by JPMorgan suggests over 60% of current South African production is being mined at a loss at current spot prices. Without continued capital expenditure, South Africa is unable to maintain its current level of production. Even if capital costs are excluded, 40% of current platinum production in South Africa is uneconomical at current levels.

Given these fundamentals we do not believe current prices are sustainable.

Best regards

Andrew Hall

Chairman and CEO

Comments (0)

  • Airdad

    Andrew is writing fiction about oil. Non of the information I have read supports his theory. Hopefully you are not investing on this guys advice.

    August 9, 2015 at 1:47 pm


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