OilVoice Magazine - April 2015

Edition Thirty Seven— April 2015

Rebuilding Reputation: Why oil and gas firms need to look within UK Heavy Oil: Recovery Factors Tax Relief for the North Sea Industry

Adam Marmaras Manager, Technical Director Issue 37 –April 2015

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

Dear Readers,

Welcome to the 37th edition of the OilVoice Magazine. We've take the very best content from our columnists and created an easy to read pdf that can be taken anywhere. We get a lot of readers telling us that they save the pdf to their phone or iPad, and then read it on a long flight or train journey. No internet connection needed. You could even print it out and take it with you. The choice is yours.

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We are still in challenging times, but the mood in the industry is still upbeat and resilient.

Markets are always going to swing, and it was just our turn.

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If you'd like to be an author for our magazine, then please get in touch. We're always on the lookout for more quality content.

Have a great Easter,

Adam Marmaras Managing Director, OilVoice.

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Table of Contents Low Oil & Gas Prices Result in Major Asset Impairments Across the U.S.

by Mark Young Palantir Forward Curve - March 2015

by Bowen Gao UK Heavy Oil: Recovery Factors

by Stephen A. Brown Middle East OPEC Oil Rig Count Jumps 14%

by Euan Mearns The Long Term Average Price Of Oil Is $30 A Barrel

by John Richardson Rebuilding Reputation: Why oil and gas firms need to look within

by Steve Girdler Tax Relief for the North Sea Industry

by Stephen A. Brown Recent history of oil suggests production will stay high

by John Richardson The oil glut and low prices reflect an affordability problem

by Gail Tverberg The Best Time for EOR is Before You Produce a Drop of Oil

by Stephen A. Brown US Shale Revolution Remains OPEC Threat Despite Low Price Pain

by Gary Hunt

2 5 8 11 14 17 19 22 25 31 34

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Low Oil & Gas Prices Result in Major Asset Impairments Across the U.S. Written by Mark Young from Evaluate Energy Large impairments rocked many U.S. companies' income statements at year-end 2014. The major cause of most of these impairments was the fall in global commodity prices in the final quarter of the year. This is the conclusion of a study looking into asset impairments using the annual data of 72 U.S. oil and gas companies (see notes 1 and 2) available in the Evaluate Energy database.

Impairment expenses occur in the oil and gas industry when the current carrying value of a company's oil and gas properties, for any given technical or economic reason, can no longer be recovered under present conditions. Our data shows 49 of the 72 companies reported such impairment expenses in 2014, the total of which is around $45 billion. It is apparent that the global fall in commodity prices, while by no means being the only reason for 2014's impairments, is the major cause for the widespread impairment expenses as a very large proportion of these $45 billion of impairment expenses occurred during Q4 and this is when the fall in prices began to take hold.

Source: Evaluate Energy

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Some companies have obviously been affected more than others by the price downturn. The chart below shows the top 10 companies whose Q4 impairment expenses make up the biggest proportion of their pre-impairment total assets at year end.

Source: Evaluate Energy

This chart shows that the impact of the fall in prices has not been limited to companies of a certain size, to predominantly oil or gas producers, or to companies focused in certain basins. The market capitalization values of the 10 companies in the chart shown above as of March 17, 2015, ranges from Swift Energy at just over $100 million up to Occidental Petroleum at over $56 billion. The companies also vary widely in their production mix: for Cabot, gas production is 95% of its total production, whereas Penn Virginia's total production comprises 75% oil. In addition, these companies have operations focused in areas across the U.S., with nearly every major onshore U.S. producing basin represented:

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Notes 1. The 72 companies included were selected because: 1. Their main production area is the United States; 2. They are based in the United States; 3. As of September 30, 2014, their market capitalization values did not exceed $80 billion; and 4. Their financial year end is December 31st.

2. The full list of companies included is available at this link 3. The percentage fall in total assets for Q4 2014 is calculated by comparing Q4 2014 impairments with the total assets figure for year end 2014 (preimpairment charge). This gives an estimate of how big an impact the Q4 2014 impairments had on a company's total assets at the end of the quarter, i.e. if it wasn't for the Q4 impairments, Goodrich's total assets figure would have been around 25% higher.

4. All impairment expenses in this report are taken from the companies' income statements throughout 2014 All data included in this article is available for download at this link. In this booklet, the impairment expenses in Q4 and 2014 and the impact of these impairments on total assets for the year is provided for each of the 72 companies. The booklet also shows the impact the fall in prices has had on the market capitalization values of all 72 companies since Q3 2014.

View more quality content from Evaluate Energy

4

Palantir Forward Curve - March 2015 Written by Bowen Gao from Palantir Global Economy

February 2015 was the first month in which crude prices increased since June 2014.

As of March 9, 2015, the WTI front month features price settled at $50 USD/bbl, increasing $3 USD/bbl compared with the January average. Brent's recovery outpaced WTI, with its front month contract priced at $58.53 USD/bbl on March 9, culminating with a $10 USD/bbl increase over the January average. This slight recovery in crude oil prices saw the reappearance of a significant price differential between WTI and Brent.

Countries that rely heavily on oil exporting revenue are facing mounting deficits.

Venezuela, Iran and Russia are among those countries that are being hit the hardest by the low price environment. Malaysia is another example where a net exporter of crude oil is facing tough times while its neighbouring countries that are net importers are enjoying the low prices.

Oil Supply and Demand The global oversupply, largely driven by record production from US shale properties, continues to hold crude oil prices at this low level. A large number of oil producers around the world have drastically reduced their capital expenditure plans for 2015.

However, these spending cuts, coupled by the associated drop in drilling activity, have yet to pull the supply numbers and forecasts down. In fact, US shale properties continue to produce at high rates, with the total stock on hand at the hub in Cushing, Oklahoma rising from 20.823 MM bbls on Oct. 31, 2014 to 51.538 MM bbls on Mar. 6, 2015. This increase in inventory does nothing to negate the fact that there will soon be an impact on supply, especially when considering that between early 2015, and March 6th,the Baker Hughes US rig count dropped by 619 (40%). Anyone familiar with unconventional upstream plays will understand how short-lived their wells are, and how this should lead to a drop in supply earlier than one would expect from a conventional play.

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Price Forecast

Our Palantir Forward Curve for March 2015 shows that crude oil prices for both WTI and Brent increase slightly faster than our previous edition of the Palantir Forward Curve, and converge to $61 USD/bbl and $68 USD/bbl respectively after 2016. The March 2015 forward curve has a much wider spread between upper and lower limits compared with the one from January 2015, which implies a higher level of uncertainty about the future price movement. The recent volatility in the options and futures markets for crude oil demonstrates this uncertainty. It is a very interesting time to watch prices as we wait to see what impact spending cuts and geopolitical events will have for the remainder of this year.

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View more quality content from Palantir

7

UK Heavy Oil: Recovery Factors Written by Stephen A. Brown from The Steam Oil Production Company Ltd

We have been developing heavy oil on the UK continental shelf for well over twenty years and the recovery factors that oil companies have achieved in the fields developed back in the nineties range from moderate (23%) to fantastic (74%), but have averaged a fairly decent 50%. The most recent spate of development projects are all envisaging recovery factors that are quite a bit lower, just 22% on average, if we ignore the Pilot steamflood project. Does this mean we have all lost our mojo, or that technology has gone backwards? It might seem so but when I analyse it in detail you will see that it is the nature of the reservoirs and the oils within them that determines the likely recovery factor.

The fields which make up the group I am analysing are all high quality Palaeocene and Eocene sandstone reservoirs deposited in a deep marine setting, so the rocks are quite similar; conversely, the viscosity of the oil in the reservoir varies considerably. Here is a chart of recovery factor vs viscosity, with viscosity plotted on a log scale. I have grouped the fields into producing (or produced) fields, the green squares, and discoveries and development projects, the orange diamonds. I have also plotted the Pilot field on the chart twice, once with the recovery factor a waterflood is expected to achieve (13%) and the average oil viscosity at reservoir temperature and again assuming a steamflood and the much reduced oil viscosity that would entail, the yellow triangles. The point of showing these two development options is that the recovery factor you get from your development is a function of what you have in the reservoirand what you do to the reservoir. It is not a fixed immutable point.

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Well there is a pretty clear trend but there is also a pretty wide scatter, and knowing the viscosity doesn't give you the definitive guide to recovery factor that we might hope for. Let's add in another parameter and see if we can tighten up the scatter on this plot. Let's try plotting recovery factor against transmissibility. Transmissibility is permeability divided by viscosity, strictly speaking also divided by formation volume factor, but we can ignore that for now as the range is pretty small and I only know the value for a few fields.

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Well, that has tightened things up a bit, there is a pretty clear relationship here, especially if we focus in on just the green squares, which are the producing fields where the recovery factors are mostly fact and only a little bit projection; by definition the recovery factors for the discoveries and developments are 100% projection. You might wish to substitute fiction for projection in the previous sentence but that would be a little too harsh on the reservoir engineering profession.

I would say that this analysis shows that most of the variation in recovery factor across these fields can be explained by just two parameters, one describing the reservoir and one describing the oil within it. Of course other things matter, such as well density, reservoir continuity and whether a field has bottom water or not, but just these two parameters help you estimate the likely range of recovery factor very quickly.

Of course, the key thing I would like you to remember is that even though the nature of the oil and the quality of the rock are fixed, the application of a little bit, or actually rather a lot, of steam can change the viscosity and boost recovery factor dramatically.

View more quality content from The Steam Oil Production Company Ltd

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Middle East OPEC Oil Rig Count Jumps 14% Written by Euan Mearns from Energy Matters As if to rub salt in the wounds of the US shale industry, Middle East OPEC oil rig count has jumped by 19 rigs to 155 units in February 2015 setting a new rig count record for the region. Since 2005 the supergiant oil fields of the region developed symptoms of mortality and increased drilling has been required to combat natural production declines in order to maintain production at static levels. More on international and US rig counts below the fold.

Figure 1 Middle East OPEC oil rig count for Saudi Arabia, UAE, Kuwait and Qatar.

Baker Hughes is not reporting data for Iran and activity in Iraq is affected by ongoing conflict. While the rest of the world is heading for the drilling exits these four Middle East countries are preparing to expand market share. All data from Baker Hughes.

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Figure 2 The International oil rig count (excluding N America) has begun to fall and this will inevitably lead to declining oil production. The decline in drilling will in fact be more pronounced than shown here since in offshore areas like the North Sea, rigs are on long-term contracts and companies are currently 'stacking' these rigs. A significant part of the drilling cost is men and materials and many companies operating offshore are simply choosing to not use rigs that they have paid for.

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Figure 3 US oil rig count continues to plunge and total rigs will soon reach the level of the 2009 lows. Notably gas rig count has now joined in the plunge and one is left wondering where this will leave US plans for self-sufficiency in natural gas let alone plans to export LNG. US natural gas production was still rising in December 2014, according to the most recent data I could find.

The dead cat bounce in the oil price has succumbed to gravity with both Brent and WTI down 4% on Friday. WTI is back to $45, close to its low of $44.12 reached on January 9th. If that does not hold then the industry is in for a renewed bout of extreme anxiety and pain. In yesterday's Blowout, Roger Andrews kicked off with a story from the IEA claiming that CO2 emissions did not rise in 2014. While the IEA want to claim victory in the war against CO2 I tend to wonder if this is not symptomatic of chronic weakness in the global economy that is implicated in the precipitous fall in the oil price.

View more quality content from Energy Matters

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The Long Term Average Price Of Oil Is $30 A Barrel Written by John Richardson from ICIS

Oil and petrochemicals markets have behaved from mid-February until today as if the world is about to return to the way it was in the first half of last year.

Here is the thinking behind this behaviour: What happened from around September 2014 onwards in crude market until midFebruary of this year was only a temporary 'supply side' problem - and not a demand problem. The supply problem was that the world had underestimated the rise of shale-oil production. Most people had also thought that Libyan output would be lower than it has been. Most importantly of all, the vast majority of analysts did not anticipate that OPEC, led by Saudi Arabia, would prefer to defend market share rather than the oil price.

'Temporary' ended up being a lot longer than most had expected, granted, but the assumption held that supply of oil would eventually start to match the new price.

Cuts in production would have to result in a price recovery - if not to $100, at least to levels much-higher than we saw in January.

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And sure enough, February saw a rally in oil prices and, in the case of Brent, greater stability around $60 a barrel.

So we have seen restocking by many petrochemicals buyers as they respond to both the rise in crude and its new-found stability. No purchasing manager for a plastics converter or a big consumer-goods manufacturer wants to be accused of failing to buy raw materials today, when the consensus view says that they might well be more expensive tomorrow.

This is the biggest factor behind the rise in Asian petrochemicals pricing since midFebruary. Supply factors in some of the petrochemicals markets themselves are also having an influence - for example, most notably at the moment in polyolefins.

But what this rally really comes down to is end-users changing their approach from the 'hand-to-mouth' buying, which was the dominant approach in September 2014 until mid-February of this year, to 'buying ahead of further oil-driven petrochemicals price rises'.

There is nothing wrong with this strategy, of course. Traders, producers and buyers of petrochemicals have been absolutely right to follow this short term trend.

Most traders, producers and buyers of petrochemicals will also be right if they demonstrate extreme caution as we get closer to Q2. The reason is that the second quarter could well see another sharp retreat in oil prices. Some analysts think that longer oil supply could drive prices down to $30 a barrel, perhaps even $20 a barrel.

But in H2 of this year, one assumption is that oil pricing will rebound - not to $100 a barrel granted, that's probably over for good - but to around today's level.

This assumption rests on the notion that what could happen in the second quarter will again be temporary because of high US inventory levels, the end of cold weather in the US and refinery turnarounds.

But first of all, you need to ask yourselves this question: Why exactly did oil prices recover in February?

The rally appears to have been driven by oil traders who made use of misleading stories about US rig counts. Although the number of rigs in operation in the US has

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fallen, production has continued to increase.

'Oil investors are making money buying and storing oil because of the difference between the current price of oil and the price of delivery in far-off months,' wrote the Associated Press in this 4 March article.

You then need to take into account these arguments: 

Oil supply will not be turned off as quickly as many people think. In the US, for example, a few dollars above variable cost margins on a barrel of oil are better than no dollars at all when you have large debs to service. Saudi Arabia is also playing the 'long game'as it tries to win back market share. This







reduces the chances of an OPEC production cut.

Demand is the thing. Yes, a lot more money is now in the pockets of consumers because oil is cheaper, but when deflation takes hold, people spend less rather than more money. It is very hard to make the case that deflation today is not a major global problem.

And once again it must be stressed that this is not 'business as usual' in China. The problems with China's economy will take many years to be fixed.

The global consequences of this reform process are huge.

And on the subject of supply again, supply of energy is vastly above demand because central bank stimulus so badly distorted our view of real, underlying demand growth. As energy-company debts left over from this critical mistake are restructured, this will add to global deflation.

So what is the right price for oil?

The chart above, from this ICIS article by fellow blogger Paul Hodges, is helpful in trying to answer this question. It shows that the long term average price of crude since 1861 until 2013 was actually just $30 a barrel, inflation adjusted.

You would be very unwise not to at least build $30 a barrel into your scenario planning.

And you would be very, very unwise indeed not to plan for extreme volatility in oil prices over the next few months and years, as the world adjusts to its New Normal whatever you think that New Normal is.

View more quality content from ICIS

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Rebuilding Reputation: Why oil and gas firms need to look within Written by Steve Girdler from HireRight

Barely a day goes by without a news story suggesting the oil and gas industry is in crisis. Following a number of scandals and a fall in oil prices, trade association Oil & Gas UK reports that the sector had seen its worst annual results since 2010, and predicts that as many as 35,000 jobs could be lost in the sector over the next five years.

As the industry looks to scale down its workforce, each role takes on a new level of importance: from rig workers to CEOs, every person employed within the sector needs to be the ideal candidate, performing with the best intentions and limiting the amount of risk oil and gas companies are exposed to. But exactly where do the risks lie?

In or Out? We spoke to HR directors in the UK's largest oil and gas organisations and found as many as nine in 10 (91 per cent) believe the biggest threats to their company are external, for instance acts of activism or hacking.

However, there have been a number of recent high profile cases - in the oil industry and elsewhere - where it has been internal issues, such as poor senior leadership, that have negatively impacted reputation and financial performance.

In some cases, organisations are focusing on preventing people from the outside affecting their business, when in reality, it is those within who almost always have the greatest impact on overall success.

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Top to Bottom

In addition, with fewer positions being made available, it's more important than ever to have the right person in each role.

Consistency is key no matter the job level. When hiring into each position, the processes used should be robust, transparent and auditable. When making a senior appointment, due diligence is even more important as an organisation's reputation rests in the hands of those at the top.

However, our research shows that at the moment only half (55 per cent) of oil and gas companies always check basic background details, like criminal record or employment history, when hiring a new CEO. This is lower than in any other sector we investigated, but why is the industry so trusting?

Three quarters (75 per cent) of high profile positions in the industry are won based on personal connections. This is 50 per cent higher than the average across all other sectors and suggests that a robust process is not carried out because organisations are relying on word of mouth, connections and influence when making important hiring decisions - rather than proven facts.

As Warren Buffet famously stated: 'it takes 20 years to build a reputation and five minutes to ruin it.' With the oil industry experiencing a turbulent period, it's time for organisations to improve their recruitment processes at all levels in order to protect from internal risks and ensure a successful future. *All data is taken from The Untouchables: Protecting Your Organisation from Leadership Risk which is based on detailed interviews with 140 senior HR leaders in regulated and non-regulated UK companies with over 5,000 employees.

View more quality content from HireRight

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Tax Relief for the North Sea Industry Written by Stephen A. Brown from The Steam Oil Production Company Ltd Last week the Chancellor offered some relief to a North Sea industry suffering from high costs and low oil prices. He didn't do it out of the kindness of his heart but rather to keep new projects coming online and to make investment in old fields that bit more attractive.

Some commentators were distinctly unimpressed as they cast around the market for the companies for whom this really mattered. There are two main reasons why they were disappointed, firstly no amount of fiddling with tax rates helps companies that are losing money on a cash basis, and secondly quite a few of the listed North Sea companies have accumulated significant tax losses (either through their own investments or clever acquisitions of someone else's mistakes) and are busy pointing out to the market that they don't expect to pay tax until sometime in the distant future; by which time the rules will have changed yet again.

There were calls for the abolition of the supplementary charge and of course that would have been great, but tax cuts for the oil industry are never popular vote winners, so the package offered is really the best we could have hoped for. The changes included a reduction in the PRT rate to 35%, a new investment allowance to replace the multitude of allowances that had sprung up when the Government realised that the uplift in the supplementary charge had stifled new investment and most welcome of all a reduction in the headline rate of the supplementary charge back down to the 20% rate at which it had been first introduced. There were other changes but since my focus is on the taxes that apply to a new project I won't go through them in detail.

For those of you who have been following what I write I had previously come up with simple charts that show roughly how value per bbl varies with oil price for North Sea projects. I will update those charts for a few projects (Lancaster, Bentley & Pilot) to show how the Chancellor's changes to North Sea taxation have helped. As always I am using a very, very simplified economic model of these fields and the calculations are based on the information in the companies' competent person's reports (CPR).

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If you don't believe the CPR projections, the numbers won't get any better just because I have massaged them, and if you want to know for sure how the economics of these projects actually look, then be patient and I am sure that the companies will provide the market with updated CPRs soon.

This chart shows those three projects before and after the tax changes. The thin lines are pre-budget economics and the thick lines are post-budget economics. Both Pilot and Bentley would have had the benefit of an Ultra Heavy Oil allowance so the uplift for these projects is a bit more modest than that projected for Lancaster. If you can't find the Lancaster pre-budget line, it is hiding behind the Bentley post-budget line. If you are pondering the reason why these three projects with such similar breakeven oil prices have such different responses, the answer lies in the pace at which the oil is produced. The slope of the line is a function of the effective tax rate and the length of time it takes to produce the barrels.

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This chart shows the impact on value per bbl on a percentage basis. You can see even more clearly on this chart that it is Lancaster than has gained the most with the tax changes. The reason for that is because as far as I could see Lancaster was not a beneficiary of any of the previous allowances. The new investment allowance, which is just a function of the amount of capital the company invests, seems much fairer and more consistent than the previous arrangements.

You might wonder then at what impact the Chancellor's announcement had on the share price of Xcite and Hurricane. Everything else being equal, assuming my calculations are right and that a long run oil price of $80/bbl applies, Hurricane's valuation improved by about 70% when the Chancellor cut SCT and gave some (tax) credit for the investment needed to bring Lancaster on stream. Hurricane's share price soared from 15.5p to 14p. Xcite had a brief moment in the sun during which their share price increased from 29p to 32p, but it was back down to 29p by the end of the day. I guess the market decided that the improved profitability of the projects increased the likelihood that these companies would raise cash by issuing shares.

But if the market is right to price Hurricane at 14p now, then it should have been pricing Hurricane at 8p before the tax changes.

On the tax system, there is still room for improvement, we would like to see some method of encouraging investment in enhanced oil recovery (EOR). We think that is something that needs to be pursued right from the start of field development and, given the uncertainties that still apply when investing in EOR, some incremental tax benefit would not go amiss.

View more quality content from The Steam Oil Production Company Ltd

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Recent history of oil suggests production will stay high Written by John Richardson from ICIS

There is a much-broader acceptance today of the recent history of oil markets, which in summary was as follows: 

Oil and other commodities became a great way to make money for



speculators at the height of the Fed's quantitative easing (QE) programme.

This was made easy because the financial system was awash with liquidity. Plus, of course, a weak dollar and low interest rates meant that returns elsewhere were paltry -quite often, in fact, negative.

China's stimulus package created the illusion of a booming global economy.



This was used by speculators as justification for driving oil prices to their levels of 2009-H1 2014.

But since then, due to the withdrawal of Fed stimulus - and most importantly of all, because of China's new economic direction - the bottom has fallen out of the oil market. It has become clear that supply is in excess of actual, real demand.

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But whilst more and more analysts are agreeing with this kind of historical thinking, I worry that some of these analysts are overlooking the impact of this history on the future - first of all, around the issue of oil industry debts and how they are dealt with.

As a result, they might be at risk of being overly aggressive in their estimates of production cutbacks later this year - and into 2016. Thus, they might end up forecasting a strong recovery in oil prices, when, instead, crude may decline even further.

The argument I have been making since last October - that oil producers will keep production higher than some people think in order to service debts - has now received support from a study by the Bank for International Settlements (BIS).

The BIS writes: 'Against this background of high debt, a fall in the price of oil weakens the balance sheets of producers and tightens credit conditions, potentially exacerbating the price drop as a result of sales of oil assets (for example, more production is sold forward).

Second, in flow terms, a lower price of oil reduces cash flows and increases the risk of liquidity shortfalls in which firms are unable to meet interest payments.

Debt service requirements may induce continued physical production of oil to maintain cash flows, delaying the reduction in supply in the market.'

In the US, as this excellent Business Insider article points out, producers have been released from the burden of debt servicing by 'capital flows from Europe and emerging markets on the back of expectation of a Federal Reserve interest rate hike'. Buoyant US stock markets, on all these capital inflows, have thus enabled local producers to retire debt in favour of equity - and by so doing, they have lowered their debt-servicing costs.

So far my coverage has focused pretty much exclusively on US shale production, given its role in driving the supply glut.

But the Business Insider also points out that heavily indebted oil companies in Russia are using current supply to pay off their debts. For example, Rosneft, the

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Russian state-owned oil company, had to in February 'front-load' oil sales in order to meet a $7 billion debt repayment. This involved supplying Trafigura, the oil trader, with 500,000 tonnes of oil in February rather than its usual 150,000-200,000 tonnes.

And there is the extraordinary story of Trinidad and Tobago offering to supply Venezuela with tissue paper, gasoline and machinery parts in return for crude oil.

This raises my second point: That governments of oil-producing countries such as Venezuela - which budgeted for much-higher oil prices in 2015 - will be prepared to take ever-more desperate steps to prevent their economies from imploding.

These measures must surely involve producing more rather than less oil, given oil is the biggest - sometimes the only real asset - of these countries. Again the same argument applies here as with corporate debt: A few dollars over the variable costs of production are better than no dollars at all, even if you end up measuring those dollars in tissue paper.

'Where's the evidence for this argument?' you might well ask. The answer is recent production trends, which are detailed in the slide at the beginning of this post, again sourced from the same Business Insider article.

The slide shows that:    

A significant proportion of the recent supply surge appeared to occur after the oil price began to drop and global oil demand started to soften.

Some of this can be explained away as the lag between oil producers noticing prices falling and respond.

A further explanation is OPEC's decision, led by Saudi Arabia, not to cut output.

But the strength of overall production in the chart above - and resilient US production growth in particular - suggests that the factors I have highlighted above are also in play.

View more quality content from ICIS

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The oil glut and low prices reflect an affordability problem Written by Gail Tverberg from Our Finite World For a long time, there has been a belief that the decline in oil supply will come by way of high oil prices. Demand will exceed supply. It seems to me that this view is backward-the decline in supply will come through low oil prices.

The oil glut we are experiencing now reflects a worldwide affordability crisis.

Because of a lack of affordability, demand is depressed. This lack of demand keeps prices low-below the cost of production for many producers. If the affordability issue cannot be fixed, it threatens to bring down the system by discouraging investment in oil production.

This lack of affordability is affecting far more than oil products. A recent article in The Economist talks about LNG prices being depressed. LNG capacity ramped up quickly in response to high prices a few years ago. Now there is a glut of LNG capacity, and prices are far below the cost of extraction and shipping for many LNG suppliers. At least temporary contraction seems likely in this sector.

If we look at World Bank Commodity Price data, we find that between 2011 and 2014, the inflation-adjusted price of Australian coal decreased by 41%. In the same period, the inflation-adjusted price of rubber is down 58%, and of iron ore is down 59%. With those types of price drops, we can expect huge cutbacks on production of many types of goods.

How Does this Lack of Affordability Come About?

The issue we are up against is diminishing returns. Diminishing returns mean that as we reach limits, it takes increased resources (usually both physical resources and human labor) to produce some type of product. Oil is product subject to diminishing returns. Metals of many kinds also are becoming increasingly expensive to extract.

In many parts of the world, a shortage of water makes it necessary to use unusual techniques (desalination or long distance pipelines) to obtain adequate supply. The higher cost of pollution control can have a similar effect to diminishing returns on

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products with pollution issues.

When we graph of the cost of production of resources subject to diminishing reserves, the result is similar to that shown in Figure 1.

What happens with diminishing returns is that cost increases tend to be quite small for a very long time, but then suddenly 'turn a corner.' With oil, the shift to higher costs comes as we move from 'conventional' oil to 'unconventional' oil. With metals, the shift comes as high quality ores become depleted, and we need to move to mines that require moving a great deal more dirt to extract the same quantity of a given metal. With water, such a steep rise in diminishing returns comes when wells no longer provide a sufficient quantity of water, and we must go to extraordinary measures, such as desalination, to obtain water.

During the time when cost increases from diminishing returns were quite minor, it generally was possible to compensate for the small cost increases with technological improvements and efficiency gains elsewhere in the system. Thus, even though there was a small amount of diminishing returns going on, they could be hidden within the overall system.

Once the effect of diminishing returns becomes greater (as it has since about 2000), it becomes much harder to hide cost increases. The cost of finished products of many kinds (for example, food, gasoline, houses, and automobiles) starts rising,

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relative to the income of workers. Workers find that they must cut back on discretionary expenditures in order to have enough money to cover all of their expenses.

How Diminishing Returns Affect the Economy There are at least three ways that diminishing returns adversely affects the economy: 1. Lower wages 2. Less ability to borrow 3. Squeezing out other sectors of the economy The reason for lower wages relates to the fact that, as the cost of producing a commodity rises, the worker is, in some sense, becoming less and less productive.

For example, if we calculate wages per worker in units of oil, as oil becomes more expensive to extract, we get something like this:

A similar chart would hold for other resources that are becoming more difficult to extract, or whose cost of production is becoming higher because of greater pollution controls. For example, we would expect the wages of coal workers to be falling as well.

Also, as we shift to higher cost types of energy, we become increasingly inefficient in energy production. Based on a 2013 analysis, in the United States, there are more solar energy workers than coal miners, even though we use far more coal than solar

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energy. The large number of workers required to produce solar energy is one of the reason that solar energy tends to be high-priced to produce.

When we look at wages of workers, we indeed see a pattern of falling wages, especially for workers below the median wage. Figure 3 from the Economic Policy Institute shows that even the most educated workers are experiencing declining inflation-adjusted wages.

A second major issue affecting affordability is debt saturation. Affordability is favorably affected by rising debt-for example, it is a lot easier to buy a new car or house, if the would-be purchaser can obtain a new loan. If debt levels stay the same or fall, this becomes a problem-fewer goods can be purchased.

Governments in particular are reaching the limits of their borrowing capacity. They cannot keep adding new debt, and remain within historic debt to GDP ratios.

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Another way debt saturation occurs relates to young people with student loans. They find it too expensive to borrow more money for a new car or for a home.

Furthermore, the fact that wages are not keeping up with price increases for many workers reduces the borrowing ability of the workers with lagging wages. This is true, even if no student loans are involved.

As mentioned above, a third issue is the fact that the inefficient sectors tend to squeeze out other portions of the economy by gobbling up a disproportionate share of workers and resources. The use of all of these resources doesn't produce a lot of goods in the traditional sense-a desalination plant is expensive, but the amount of water produced per dollar of investment is not large. To the extent that the high costs of inefficient sectors are passed on to consumers, consumers find that they must cut back on discretionary spending. This cut-back in spending squeezes out discretionary spending, leading to cutbacks in discretionary sectors, and to reduced employment overall.

Wishful Thinking by Economists Back before diminishing returns started becoming a major problem, economists created models regarding how the economy would react to higher cost of energy production and other symptoms of diminishing returns. In their view, if the cost of oil extraction rises, oil prices will rise to match these higher costs. Alternatively, substitution will take place, or technological changes will allow greater efficiency, or customers will cut back on their use of the high cost product. Somehow, these changes will take place without a particularly adverse impact on the economy.

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Unfortunately, the models don't correspond very well to what happens in practice-at least not for very long. It takes inexpensive energy to produce goods that workers can afford. Higher priced energy does not work well in this regard. Feedbacks that are not reflected in economic models reduce both wages and debt, making it harder to buy goods requiring the use of more-expensive energy products.

Furthermore, if the price of one commodity, for example oil, rises, then countries with very much oil in their energy mix find themselves handicapped in trade with other countries that use less oil in their energy mix. For example, a country that depends on tourism (which depends on oil use) for very much of its revenue, such as Greece, finds it difficult to find customers when oil prices are high. Lack of revenue can lead to financial problems for the country.

Because of the networked way the economy really works, prices for commodities can't rise for the long-term. They may rise for a while, as consumers and governments borrow more, in an attempt to continue business as usual. Ultimately, though, the situation can't 'work.' Customers can't afford to buy more homes and cars, unless their own wages are rising in inflation adjusted terms, and governments can't collect enough tax revenue.

The issue we are dealing with here is lack of affordability. This is what will bring the system down-not the high priced scenario imagined by many. Decline will come through low prices, and a glut in oil supply, even if we are not looking for it from that direction.

Can commodity prices rise again?

It is not all that clear that they can rise again. It would be a lot easier for commodity prices to rise, if the problem were simply inadequate prices of one commodity, leading to a lack of that commodity. If the problem is inadequate demand for crude oil, coal, LNG, and iron ore the problem is much greater-especially if wages are still lagging.

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The Best Time for EOR is Before You Produce a Drop of Oil Written by Stephen A. Brown from The Steam Oil Production Company Ltd The sad truth of working in oil companies is that being assigned to work on enhanced oil recovery ('EOR') projects is sometimes considered career death. All the glamour jobs are on the big discoveries, putting in place billions of dollars of plant and equipment and bringing on hundreds of thousands of barrels per day of production. EOR is thought about as fields decline and managers are looking for some way to stave off decommissioning or being assigned to the 'Acquisitions and Disposals' basket.

Even the terminology we use consigns EOR to the difficult end of field life. Primary recovery (just let the oil flow), secondary recovery (well we better pump some water in then) and tertiary recovery (EOR, or darn it that hasn't worked so well what else can we try). That sounds like a logical sequence, but that isn't the way it should be at all.

All EOR techniques are really about trying to reduce the residual oil saturation below that which you would get with a waterflood. I don't count infill drilling as an EOR technique, in fact most people would call that Improved Oil Recovery ('IOR'), infill drilling is just a sensible way to phase the drilling schedule so that you know more about the reservoir when you drill half of your wells, it makes sense to do that after producing most of the easy oil. However, by implementing EOR projects late in field life we defer, by twenty years or more, the extra production we get from the reduced residual oil saturation and because we have replaced all of the easy oil with water we make the new displacing agent (fresh water, carbon dioxide, steam, polymer thickened water, whatever) work two or three times as hard. That's because it has to displace the water we injected as well as the little bit of extra oil we hope to get. No wonder most EOR projects don't pass economic thresholds.

Conversely, do it from the start, as BP is doing on Clair Ridge, and we intend to do

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on Pilot, and you get the extra oil early and therefore the economic benefits are magnified. Doing it from the start helps reduce the costs too. Retrofitting a reverse osmosis plant on an offshore platform would cost many times more than building it into the platform in the construction yard. Doing it from the start gets the most value possible from the technology.

So why doesn't this happen, why are the EOR sections of most companies websites talking about what they might do some time in the distant future? Why isn't EOR built into development plans right from the start?

The answer is that the oil industry is very conservative, and especially cautious when designing new projects. With good reason, oil fields are uncertain beasts, just as likely to disappoint as to do what we expect. Implementing a different sweep mechanism means taking a risk, it means doing something that your predecessors haven't. In fact the industry has designed a series of project evaluation processes designed to hammer risk out of projects, the trouble is they tend to steer us all towards the conventional option, the well travelled path. Innovation is stifled, opportunities bypassed, just like the oil we will leave behind.

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Most of the technologies aren't that new, low salinity water is a recent technique, but most of the rest have been around since the sixties and seventies. We all know that carbon dioxide injection would be a massively successful EOR technique for a typical light oil North Sea reservoir, but there isn't a single project trying to take advantage of that benefit. Neither of the carbon capture projects mooted in the UK are doing anything other than pumping the carbon dioxide into the ground to store it, there seem to be no plans to take advantage of its magical oil recovering powers.

For some fields, there are good justifiable reasons why no-one is taking up this opportunity. Existing wells and process systems in a lot of currently producing fields don't have the metallurgy capable of coping with corrosive carbon dioxide. But for other fields where the original oils were sour with high carbon dioxide content, fields such as Brae, Miller, Trees, T-Block and Kingfisher, the process systems are ready to deal with carbon dioxide breakthrough and there is no good technical reason not to try a carbon dioxide flood. There is even carbon dioxide available nearby from Sleipner. But because people have delayed thinking about EOR until the end of field life, the margins on the incremental barrels are smaller, and the opportunities are slipping away from the industry.

So implementing EOR needs to be in every new field development plan, right from the start. That should be part of the new Oil and Gas Authority's mission. The OGA needs to make operators justify why the techniques, which are effective for the type of reservoir a company wants to develop, can't be applied right now, right at the start of development. The mindset needs to change from having operators justify why EOR will work, to justifying why it can't work.

The industry won't change on its own, it needs a carrot (a decent tax incentive) and it needs a stick (a robust regulator).

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US Shale Revolution Remains OPEC Threat Despite Low Price Pain Written by Gary Hunt from Tech & Creative Labs LLC

The shale revolution is levelizing the energy marketplace, undermining the pricing power of OPEC, reducing US oil imports, turning natural gas exports as LNG into a big factor in global markets and redefining future market rules. This is a big deal. And OPEC knows it cannot stop it.

US oil production from the shale revolution is way up as oil production rose to 9.077 million barrels a day, the highest level in weekly according to data from the Energy Information Administration going back to 1983. At the current pace the US is expected to set a new all-time high in oil production surpassing 9.637 million barrels of oil per day by 2016.

According to IHS, only about 20% of producers need $90 a barrel to break-even and 'about 80% of the tight oil estimated to be pumped in 2015 will still be profitable at between $50 and $69 a barrel'

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In a recent presentation Lynn Helms, Director of the North Dakota Department of Mineral Resources, told the House Appropriations Committee: 'North Dakota needs an oil price of around $55 per barrel at the wellhead and a fleet of about 140 rigs to sustain production at the current level of 1.2 million barrels per day.' However, the breakeven costs vary significantly, with producers using fracking methods requiring significantly higher prices, 'breakeven costs reflect a price at which new drilling would cease' and 'production from existing wells would be shut-in at $15/bbl.' Lynn Helms' view seems to be supported by independent analyst.

Although IHS estimated that a price of $60 a barrel would see oil sourced from fracking drop to as low as 350,000 bbl/d - down from 700,000 bbl/d at $77/bbl - some producers may be able to initially survive lower prices due to the fact that many associated infrastructure costs are already sunk if they have manageable debt loads.

But it will become increasingly difficult to get new investment and loans as profit margins are squeezed to break-even prices or below. Small producers will be first and the worst affected.

The shale revolution unlocked the entrepreneurship, ingenuity and resolve of American producers in ways that are difficult for Saudi princes to grasp. Three factors explain why the US shale revolution has a high probability of success against the enormous pressure and market of the Saudi decision to drive down global oil prices: 1. Private Property Rights for Mineral Holders. In most nations mineral rights are owned by the government. That is why we see so many national oil and gas companies and government involvement in the E&P development of resources. The government benefits from the revenue produced from the extraction and sale of the resources. In many case, those governments confiscated private companies and property essential to production. Today some of the biggest national oil and gas companies rival the size of the super majors or are larger. In the US individual land owners retain the mineral rights underlying their property. Landsmen scour attractive plays for opportunities to acquire leases from property owners. Some plays have seen 'land rush' enthusiasm for leasehold acquisitions bidding up the price of leasehold bonuses the up-front payments landowners typically receive for granting the right to drill on their property.

2. Disruptive Innovation Drilling Technology and Persistence. The persistence and skill of the pioneers like George Mitchell made the shale

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revolution possible through their trial and error perfection of new drilling techniques and equipment in horizontal drilling and hydraulic fracturing to make drilling economic in the tight oil and gas. Adding better seismic study of the geology formations has also greatly improved the targeted of drilling operations.

3. Market Structure of Oil & Gas Contracts and Leases. Another key factor in the success of the shale revolution has been the nature of contracts and the balancing of interests and incentives between property owners and producers.

Drilling oil and gas contracts typically contain specific clauses such as a 'Habendum clauses' that define how long the interest in leasehold will be granted. Most oil and gas leases have a primary and secondary term. In the primary term the lessee can hold the lease without producing, but during the secondary term the producer is required to produce in order to retain the lease rights usually described in language something like 'so long thereafter as oil and gas is produced in paying quantities.' The reason for this the owner wants to avoid tying up his property without revenue as landsmen try to assemble acreage and hoard it for later use. Often called 'hold by production' these contracts are a big factor in the continued growth of onshore US oil and gas production growth even if the wells are marginal or uneconomic. Leases like these created a 'forced production' pressure on the lessee to keep producing in order to retain his lease rights even if he is underwater.

The US shale revolution in being tested by the falling price market conditions but it is unlikely to be derailed by OPEC or other market factors. We are seeing the resilience, agility and entrepreneurship that George Mitchell instilled in the birth of the shale revolution still paying dividends in disruptive innovation improvements by driving down break-even points, enabling continued production even when some wells are underwater as shale producers battle hardened from the experience may become ever more fierce competitors.

Low oil prices hurt America's shale producers, no question about it, but it is turning them into even more fierce competitors with lower break-even prices and abundant supply.

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