OilVoice Magazine - May 2016 - Edition 50

Edition Fifty — May 2016

OPEC dies in Qatar The Next Big Fight in Oil If Prices Rise Natural Gas Prices Should Double

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Natural Gas Prices Should Double Written by Art Berman from The Petroleum Truth Report Natural gas prices should double over the next year.

Over-supply plus a warm 2015-2016 winter have resulted in low gas prices. That is about to change because supply is decreasing (Figure 1).

Figure 1. EIA U.S. natural gas supply balance and forecast. Production, consumption and supply balance values are 12-month moving averages. Source: EIA and Labyrinth Consulting Services, Inc. Total supply-dry gas production plus net imports-has been declining since October 2015* because gas production is flat, imports are decreasing and exports are increasing. Shale gas production has stopped growing and conventional gas has been declining for the past 15 years. As a result, the supply surplus that has existed since December 2014 is disappearing and will move into deficit by November 2016 according to data in the EIA March STEO (Short Term Energy Outlook) .

During the last supply deficit from December 2012 to November 2014, Henry Hub spot prices averaged $4.05 per mmBtu. Prices averaged $1.99 per mmBtu in the first quarter of 2016 so it is reasonable that prices may double during the next period of deficit.

EIA forecasts that gas prices will increase to $3.31 by the end of 2017 but that is overly conservative because it assumes an immediate and improbable return to production growth once the supply deficit and higher prices are established (Figure 1).

Production companies are in financial distress and are unlikely to return to gas drilling at the $2.75 price that EIA forecasts for November 2016. The oil-field service industry is in disarray and is probably unable to reassemble drilling and fracking crews and equipment in less than 6 to 12 months after demand resumes.

There are currently on 92 rigs drilling for gas. That is 150 rigs less than the previous record-low set in 1992 (Figure 2). Production cannot be maintained at this level despite unrealistic faith in drilling efficiency and spare capacity from uncompleted wells.

Figure 2. U.S. gas-directed rig count, 1987-2016. Source: Baker Hughes and Labyrinth Consulting Services, Inc. A Tale of Two Price Cycles Storage and production patterns for 2015 - 2016 appear quite similar to patterns observed in 2011 - 2012. Both periods are characterized by exceptionally high storage and comparative inventory levels, and record-low spot gas prices.

The storage and comparative inventory surplus of October 2011 - March 2012

disappeared as gas supply fell in response to low prices (Figure 3). By April 2013, gas prices were near $4.20 because the surplus had become a deficit. A cold winter sent prices above $6.00 in February 2014. A similar pattern may be occurring in 2016.

The monthly average Henry Hub price for gas in March 2016 was $1.71 per mmBtu. That is the lowest CPI-adjusted monthly price (February 2016 dollars) in 40 years (Figure 3 shows 1999-present). The previous record low price was $2.01 in April 2012. The 2012 low coincided with a comparative inventory peak followed by an inventory deficit and gas prices that exceeded $4.00 by December 2013. The current 2016 price low must be near the latest comparative inventory peak.

Figure 3. U.S. natural gas storage and CPI-adjusted Henry Hub spot price in February 2016 dollars per mmBtu. Source: EIA, U.S. Bureau of Labor Statistics and Labyrinth Consulting Services, Inc. Comparative inventory is a measure of gas storage volume compared to a moving average of inventory values for the same time period over the 5 previous years.

Comparative inventory (CI) provides an excellent negative correlation with natural gas spot prices.

Absolute storage levels were nearly the same for the last week of March 2016 (2,468 Bcf) and the last week of March 2012 (2,472 Bcf), and 2016 appears to be trending lower relative to 2012 (Figure 4).

Figure 4. Comparison of U.S. natural gas storage levels, 2012-2016. Source EIA and Labyrinth Consulting Services, Inc. Gas production was flat from February 2012 through December 2013 in response to the price collapse that culminated in April 2012 (Figure 5). The price minimum coincided with a supply surplus maximum that disappeared and became a supply deficit by February 2013.

Figure 5. Dry gas production, Henry Hub prices and total supply surplus or deficit.

Supply surplus and deficit values represent 12-month moving averages as in Figure 1. Source: EIA and Labyrinth Consulting Services, Inc.

Gas production has been flat since September 2015 (Figure 5). Total dry gas production in March 2016 was 0.7 bcfd less than in September 2015 and the latest EIA data indicates that production for April is 1.2% (-0.83 bcfd) less than a year ago.

EIA's supply forecast (Figure 1) suggests that the present surplus will become a deficit later in 2016.

Why Natural Gas Prices Will Double I used the EIA March 2016 STEO inventory forecast to calculate comparative inventory for the rest of 2016 and 2017. This data indicates a fall in comparative inventory beginning in April or May 2016 (Figure 6).

Figure 6. U.S. natural gas comparative inventory, Henry Hub price and forecast.

Source: EIA and Labyrinth Consulting Services, Inc. That should result in a return to higher gas prices. The price estimate based on comparative inventory (shown in red) is more bullish than EIA's price forecast (shown in orange) but both indicate a substantial percentage increase in prices. EIA forecasts $3.20 gas prices in January and February 2016, and $3.41 in December 2017. My forecast based on comparative inventories is about 15% higher overall than EIA's but peak prices are 20-30% higher. It calls for winter prices in the $4range for 2016 and 2017.

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Hedge funds exit oil price rally as Saudi plans post-oil economy Written by Paul Hodges from ICIS

'Within 20 years, we will be an economy or state that doesn't depend mainly on oil'.

This critical statement from Saudi Arabia's deputy Crown Prince has been lost in the hype surrounding Q1′s hedge fund-inspired rally in oil, commodities and Emerging Markets. There has seldom been a better example of markets failing to see the bigger picture by remaining focused on day-to-day detail.

But Q2 is likely to see attention return to the fundamentals of oil market supply and demand. As the chart shows, this week's commodities market data showed the hedge funds were already starting to take their bets off the table. This is hardly surprising, with prices having jumped 50% in a matter of weeks: 



Iran is successfully re-entering the market, with its exports to India already up 4-fold since January to 500kbbl/day, and other Asian countries also keen to buy US storage operators are resorting to ever-more desperate manoeuvres to stop their tanks from over-flowing

As I warned last month, the rally had nothing to do with a rebalancing of oil markets either via major cuts in production, or a sudden increase in demand. Instead, it was all about the funds betting, correctly, that further stimulus was on the way from the central banks. As the Financial Times noted: 

By the end of March, the funds had built a record long position of 579m bbls in



Brent/WTI This was equivalent to almost 6 days of global demand

But last week, they began to take their profits and close their positions. Chemical markets thus face major challenges:   

Prices for the major petrochemicals are highly correlated to crude oil prices most are more than 95% correlated So sales managers are already busy raising their prices to try and maintain their margins Purchasing managers are meanwhile building inventory to protect their own margins

And they are not alone. The Q1 rally spread across the commodity sector, and led to major bond and share price rises for commodity exporters and Emerging Markets.

But none of the move was real. It was simply the hedge funds spotting a short-term opportunity for profit, based on the realisation that another central bank panic was on the way.

So now, as one would expect, the smart funds are not hanging round to see what happens next. Of course, US oil inventories will reduce as we head into the main driving season. But fundamentals didn't drive the rally, and the funds know all-toowell that sudden rallies can disappear as quickly as they appeared.

Attention is thus likely to turn to last week's 5 hour Bloomberg interview with the deputy Crown Prince of Saudi Arabia. It confirmed, as I have argued for the past 18 months, that Saudi is focused on making plans for the post-oil world and highlighted, for example: 'His obsession with moving the Saudi economy away from oil...Aramco's new strategy will transform it from an oil and gas company to an energy/industrial company'.

Companies and investors have to follow market trends, as they cannot afford to be on the wrong side of 50% rallies. But they also have to recognise that the biggest rallies always occur in bear markets. Oil's next move may well be another 50% decline, and as I warned last month: 'If prices collapse again as the hedge funds take their profits, companies will face the risk of bankruptcy as we head into Q3. They will be sitting on high prices in a falling market - just as happened in January. Only Q3 could be worse, being seasonally weak, and so it may take a long time to work off high-priced inventory'.

Beware Of Oil-Price Rally: Nothing To Do With Fundamentals Written by John Richardson from ICIS

PEOPLE are once again at risk of dangerously over-exposing themselves to a further collapse in oil prices following yesterday's increase to the highest levels since November 2015. The obvious risk is that there will be stock building up and down all the petrochemicals values chains, only for oil to once again decline in Q3 or the underlying fundamentals.

Here are a few critical points that you must take into account in your scenario planning.

One of the increasingly widely-held assumptions is that the producers' meeting in Doha on Sunday about a possible production freeze could be the prelude to an

eventual production cut.That is at least an admission that a freeze by itself won't be enough, given current record-high levels of output.

We have to consider how likely it is that a cut will occur. I for one don't see it happening...

Why? Because Iran is easing itself back into the global market in a much bigger way and its long term aim is to win back market share to make up for the economic ground lost as a result of sanctions.

We should also listen to Daniel Yergin, author of course of The Prize, the book that everyone with an interest in oil and energy should read.

Yergin told the FT: 'The era of Opec as a decisive force in the world economy is over. It is clearly a very divided organisation.

I remember when the operating code was: save the oil for our grandchildren. Now the grandchildren are in charge and they are looking at it in a very different way.

They are not looking at it as precious resource . . . but rather asking how do you monetise it?'

Hear, hear. One of the underlying messages of Yergin's book is that it is not only the cost of production that ultimately counts in oil markets, but it is the social and political factors that drive the industry.

So I remain convinced that Saudi Arabia -, as of course the world's biggest producer - doesn't want to risk leaving its most valuable asset in the ground because we have gone beyond the point of peak oil demand growth.

A fascinating Bloomberg interview with Saudi Deputy Crown Prince Mohammed bin Salman is further essential reading on this point. Prince Mohammed talks extensively about adding greater downstream value as the Kingdom attempts to move into a post-oil economy.

The approach is thus to pump as much oil as possible in the short term, in order to, as I said, not leave this vital assets in the ground, whilst using today's low prices as a means of pushing the Kingdom more aggressively away from overdependence on crude exports.

Back in October 2014, I also made the point that US shale oil producers, if they went bust, would not stop operating. This Reuters article confirms what I suspected - that producers in chapter 11 have every motive to carry on pumping crude.

I have also flagged up the steep fall in shale-oil production costs, which Reuters again underlines when it writes in the same article on chapter 11: With operating expenses for existing US shale wells between $17 and $23 per barrel, most companies can keep pumping unless oil falls below $20 per barrel, says David Zusman, chief investment officer of Talara Capital Management.

And again you have to consider the social and political factors here. Following the lifting of the US ban on exporting crude, the US has a great opportunity to take more advantage of one of the few genuine bright spots in its economy. This will very likely involve maximising these exports to create jobs.

Sure, today's rally might have more legs, but please be aware of all the above important context and accept this: That this rally is not about fundamentals, but is instead another great example of 'after the fact' story telling. Prices have gone up mainly because hedge funds have gone long, rather than short, in oil. And they have gone long because they expect oceans of more cheap money with which to gamble in equities, oil and commodities in general.

These extra oceans are expected to be available due to more European Central Bank and Bank of Japan economic stimulus and the indications that the UF Federal Reserve has become lukewarm on further interest rate rises. People have, after the event, sought a rational in physical markets for what is mainly a rally built on the behaviour of financial markets.

The risk is therefore of another sudden retreat in crude that takes the petrochemicals business off guard. Possible triggers for this? 

  

Well, first of all, just look at US crude inventory levels in my above chart. They remain at their highest levels since 1982. When people start staring at these types of charts again, this could severely dent today's positive sentiment.

A disappointing Doha meeting this Sunday.

The end of the US driving season after the 4 July holiday.

Q3 demand is always seasonally weak before it picks up again for restocking ahead of winter.

So please, please: Be very careful out there.

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Can OPEC 'freeze' production, or is it already frozen?

Written by Roger Andrews from Energy Matters Between July 2014 and January 2015 the price of OPEC's oil 'market basket' fell from over $100/bbl to less than $50/bbl, causing considerable hardship to the OPEC countries who rely on oil exports to finance their national budgets - which is all twelve of them. Under these circumstances the logical reaction for a cash-strapped, oil-rich country would be to pump more oil to increase revenues , yet only two - Saudi Arabia and Iraq - actually did so. The remaining ten, which account for over 50% of OPEC's current total output, seem to have already been pumping as fast as they could or were prevented from doing so by civil war (Libya) or sanctions (Iran) or by other factors outside their control. The implication is that all the talk about freezing OPEC production at January 2016 levels may be just so much hot air. With Saudi Arabia also now pumping at capacity according to Euan's March vital statistics post OPEC may no longer be capable of increasing production above current levels even if it wanted to.

We begin with a comparison of monthly OPEC market basket prices with total OPEC crude oil production (data from OPEC). The plot runs from July 2014, when the oil price 'collapse' began, through March 2016:

Figure 1: OPEC crude production versus OPEC 'Market Basket' price, July 2014 through March 2016

OPEC held production relatively stable between July 2014 and February 2015 but then abruptly increased it by 1.6 million bbl/day - about 5% of production - between February and June 2015, and since then production has once again stabilized. The timing of the increase leaves little doubt that it was at least partly a response to the price collapse, but the production increase came almost entirely from two countries, with Saudi Arabia adding 750,000 bbl/day and Iraq adding 850,000 bbl/day. The Saudi increase was probably a policy decision but the Iraqi increase is less easily attributed. It may simply have been a continuation of Iraq's ongoing attempts to rebuild its oil industry aided by a December 2014 deal with the Kurds which increased the contribution from Iraq's 'northern oil' by 451,000 bbl/day in May 2015.

Now a quick look at OPEC production by country. Figure 2 shows the little fish, with the Y-scale fixed at 3.5 million bpd so that you can tell the countries apart (data from Peak Oil Barrel, which obtains its data from OPEC monthly reports and contains expanded graphs of OPEC production by country if anyone wants to review them). Apart from the fluctuations in Libya and the erratic behavior of Angola and Nigeria the lines are close to flat. There's no obvious sign of a production response to lower oil prices. (The abrupt rise in Iranian production after January 2016 reflects the lifting of sanctions; the reasons for the equally abrupt decrease in UAE production that effectively offsets it are not known.)

Figure 2: OPEC crude production from smaller contributors, July 2014 through March 2016 Figure 3 now adds the bigger fish. The January-May production increases in Saudi Arabia and Iraq are evident. So is the extent to which Saudi Arabia continues to dominate OPEC production:

Figure 3: OPEC crude production by country, July 2014 through March 2016 Table 1 shows production changes by country between the time the oil price began to crater in July 2014 and March 2016. The countries are sorted by the absolute change in production:

Since July 14 OPEC has increased its combined production by 5%, but without Iraq the number falls to 1%, and if we add Iran we are looking at a small production decrease. Apart from Iraq and Iran only Angola has increased production by more than 5%. Production in Saudi Arabia, Ecuador, Venezuela, Kuwait and arguably the UAE has remained effectively flat while in the remaining four countries it has decreased by up to 18%. Not only were these four countries (Qatar, Algeria, Nigeria and - unsurprisingly - Libya) unable to pump more oil to generate desperatelyneeded cash, they apparently weren't even able to stop ongoing production declines.

Which leads to the question of whether OPEC's strategy of not cutting production to preserve its market share has worked. Generally it has, with OPEC's share of world production falling only by 0.3% between July 2014 and March 2016, according to OPEC monthly reports. Only three of the twelve OPEC countries, however, have succeeded in increasing their market share - Iraq, Iran and Angola. The rest, including Saudi Arabia, have lost slightly:

And what of OPEC's future production? This being the oil market it's unpredictable, but the data presented here suggest that unless an unprecedented and lasting peace breaks out between the squabbling and war-torn MENA countries in the next year or two it's unlikely to increase. An OPEC production freeze seems inevitable regardless of attempts such as the recent Doha Meeting to negotiate one. A quick glance back at Figure 1 shows that a de facto freeze has in fact been in place since June 2015, but not because OPEC planned it.

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Is There A Perfect Storm Coming for Natural Gas Prices?

Written by Keith Schaefer from Oil & Gas Investments Bulletin Even before Tuesday's big jump in natural gas prices, I was intrigued to see some of the leading natgas stocks in the US hold up or go up on days natgas was down this week, like EQT, Southwestern, and Rice Energy, (which my colleague Bill Powers profiled at $9.47/share on Feb. 9 and is now up 80% in two months)...I thought traded quite bullishly last week week.

Fundamentally, there is a very bearish 1 Tcf (TRILLION cubic feet) YoY surplus of natgas inventories in the US. But investors have to remember that bloated inventories are today's news, and the Market tries to price in what it thinks will happen in the future, 6-9 months from now.

The Street is seeing natgas production almost flatten in the US so far in 2016, after jumping 4-5 bcf/d each of the last two years. That is somewhat bullish, though production flattened in 2013 as well before making those big jumps in '14 and '15.

Overall natgas demand has steadily kept up (mostly) with production, and is really the untold story of this market over the last few years.

And now the Weather Gods could co-operate with the bulls. This summer is expected to be hot-like 2012 hot-which saw corn yields shrivel and corn prices soar.

Natgas prices also doubled off the lows from April 2012 to December 2012.

A hot summer isn't near as bullish as a cold winter (3-4 bcf/d more demand for hot summer but up to 10 bcf/d for a cold winter), but we may get a cold winter coming (2016/2017) as the National Oceanic and Atmospheric Administration's (NOAA) Climate Prediction Centre came out on April 14 saying there was a good chance of a La Nina weather system for next winter.

La Nina is kind of the opposite of El Nino (not 100% different), especially along the heavily populated and high natgas-consuming region of Chicago to the NE US coast.

A colder winter can mean up to 10 bcf/d difference in overall natgas usage from NovMar, which is what the natgas analysts mean when they say 'winter'. That's a lot; over a 10% swing at 90 bcf/d.

La Nina means the Pacific Ocean is getting warmer. El Nino means eastern Pacific waters are colder (just off Mexico).

And in the Atlantic, a huge mass of cold arctic water the northern part has kept the Gulf Stream quite far south, so there is a build-up of warm-very warm-waters there.

That could mean storms and hurricanes. Hurricanes used to be a big deal for natgas prices because the Gulf of Mexico (GOM) used to provide a higher percentage of overall US production. Now it's just a hair over 4%.

GOM natural gas production is down about 50% since 2000. That will increase in the coming years as there was a dearth of new production after the Macondo/BP oil spill in April 2010-but several new projects are coming online in the coming two years.

So if there is a really warm summer this year, that could mean 4 bcf/d extra demand, and over 150 days that would more than half the current 1 Tcf YoY storage surplus and allow low cost producers to lock in some great profits.

Costs for natgas producers have come down a lot-more than people expected. I see sub $1/mcf all in costs for some producers now. I saw how Canadian Montney producer Painted Pony (PPY-TSX) hedged like mad at $2/mcf recently because they make good money there.

So between warm Atlantic waters this summer and La Nina this coming winter from the Pacific, natgas investments in the coming 1-3 months could be very lucrative.

Does that create The Perfect Storm for natgas stocks?

As in oil, leading US natgas stocks have had a big jump in the last four weeks. As an investor I wonder how much of that is the Dow pulling everything up and how much is really natgas related. But charts of leading stocks in both commodities are surprisingly similar-strong bounce off mid-February lows through the short and mid term moving averages all the way up to the 200 dma.

Now the moving averages are narrowing quickly-and that usually presages a big move of some kind. If I had to guess now, I would say that it would be up.

But fundamentally, very little if anything has changed recently. Perhaps the Market is saying that any month that US natgas production is only up 1 bcf/d YoY is bullish.

The stocks of Canadian natgas producers will rise in some sympathy, but Alberta and B.C. are at the back of the pipe so to speak, far from major markets. That means higher transportation costs, which means lower realized prices for producers to stay competitive. Lower realized prices=lower stock prices.

And the Pacific Northwest got buckets of rain this winter, about 130-150% of normal, so hydro-electric supply should be a lot more this year, and Canadian natgas filled that demand the last couple years. This is a bit bearish for Canadian natgas.

Despite Canadian producers like Painted Pony doing an excellent job reducing costs down to sub $1/mcf costs, I see the first Big Move in natgas stocks being in the US. Or has it already happened?

EDITORS NOTE - Who would have thought in January 2016 that Tier 1 oil and gas stocks would double from February to April? What happens now? Lucky for me, I know the one western producer that has lower costs than the Saudis. Nobody else can grow like this company at $45 oil. And if oil goes to $70, it will have the largest profit margins of any producer I know. Get Ready.

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Price shock: how the gas industry is weathering the oil crash Written by Diane Kraal from The Conversation

Falling oil prices are causing a shake-up in the gas industry. The latest sign of this is Australian energy company Woodside's indefinite deferral of its huge gas project off northwest Western Australia.

The A$40 billion project was to convert natural gas extracted from deepwater areas to liquid (LNG) on a floating barge-like structure for export - a world first on a commercial scale. Major oil companies Shell and BP are partners in the joint venture. Some have suggested the solution is for companies to work together to bring down costs.

The project is just the latest victim as companies adapt to lower oil prices. So how else is the sector dealing with the low prices?

Why have prices fallen?

Gas prices are linked to oil prices in their export contracts. Oil prices started their freefall from around US$110 a barrel in July 2014 to the current US$38 a barrel.

Shell has claimed that the project is not economic at an oil price of less than US$50 a barrel.

Essentially, the global oil and gas industry is facing an oil price shock, which is affecting local projects.

The price of oil has fallen as non-Western oil-producing countries (OPEC) seek to reestablish dominance over the United States. The recent US shale oil revolution uses new extraction techniques, so despite its higher costs requiring higher prices, shale oil was looking like it might make the United States self-sufficient in oil for the first

time. But the OPEC competitors have flooded the market with oil (thus lowering the price) in a bid to drive US shale oil companies out of business.

Other oil states such as Nigeria, Iraq and Venezuela have compounded this oversupply by ramping up production for much-needed cash to shore up their weakening economies.

The ramifications of 'low oil price shock' are being discussed in oil and gas professional journals, but academic journals haven't yet caught up.

To find out how companies are dealing with the price shock, I and other researchers have been interviewing senior executives from the oil and gas industry in Australia and Malaysia. We're starting to see some definite trends.

Cuts to exploration and new spending After decades of exploration in Australia for oil and gas, industry is cutting its spending on exploration.

Several executives mentioned that spending on new projects has been curtailed in the design and development phase. One commented, 'We've already had several rounds of capital budget cuts.' The overall impression from the interviews is of a significant drop in the number of projects globally that are progressing to the development phase, which normally requires significant spending.

One oil executive called for Petronas (Malaysia's national oil company) to pull back on capital spending on overseas ventures, such as those in Australia, and spend on projects in Malaysia.

Retrenchments and asset sell-offs In terms of the low oil price impact on employees, one comment was: 'There is a blood bath going on.'

An executive stated: 'It is my view that non-critical and expatriate staff will not see their employment extended.'

Another explained: '...in the short term, we have had a lot of job cuts and a lot of salary reductions.' Thousands of jobs are being axed and the industry's professional journals are counselling those affected.

Roger Jenkins, chief executive of US Murphy Oil Corporation, recently reflected on his company's 2015 operations in Sarawak, Malaysia. He cited lower operating costs, such as savings on labour, and the 'timely 30% selldown' of onshore plant assets in Malaysia. At the moment cash is sorely needed.

Maintain cash flow and preference onshore projects Jenkins observed that Murphy Oil's capital expenditure will be cut to less than US$2 billion in 2016 and the company will reduce risk by getting out of deepwater operations, such as floating LNG facilities.

The plan is to survive the downturn in oil prices by maintaining current production projects (for cash flow) and keeping operations close to shore. Anything nonproductive is being sold.

Another oil executive said cost savings have mainly been found through onshore technology, while deepwater offshore projects remain costly. His view was that as companies dispose of non-productive assets, there are going be 'buying opportunities this year'. He also predicted that this quarter in the US over 100 small oil and gas companies are going to file for bankruptcy.

The deferral of Woodside's major floating LNG project in the Browse Basin is part of the fallout from the low oil price shock. The next step is to figure out what this will cost the Australian economy.

Diane Kraal - Senior Lecturer, Business Law and Taxation Dept, Monash Business School, Monash University, Monash University

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Saudi Arabia, Refining And The Battle for Crude Market Share Written by John Richardson from ICIS

SAUDI ARABIA is determined to win its battle for greater market share of the global oil market, and at the same add value downstream to its hydrocarbon reserves. This is the consistent message I have picked over the last 18 months.

And so a report in the Financial Times that Saudi Aramco plans to double its refinery capacity to 10m bbls/day fits very neatly with these overall objectives.

The FT adds that Aramco, in a bid to both lock in greater crude sales and, as I said, add more value to oil, plans to achieve this doubling of refinery capacity through possibly acquiring more overseas refineries in China, India, Indonesia, Malaysia and Vietnam. This month, Aramco announced plans to take full control of the 600,000 bbs/day Port Arthur refinery in Texas, the biggest in the US. It already has part ownership, along with Shell and Motiva Enterprises.

'This is the future Saudi export strategy,' Krane, a fellow at Rice University's Baker Institute for Public Policy told the FT. 'Create captive markets in important importing countries by owning refineries in those countries. That way their market share is secured.'

Why not perhaps, therefore, Saudi acquisition of more refinery-based petrochemicals capacity overseas, and/or expansions at home?

The problem for Saudi Arabia is that for the time being at least, it is losing ground in the market share battle. Data quoted in the same FT article shows that the Kingdom's share of exports to the key China market fell in 2015 as Russia gained ground. In South Africa, Saudi Arabia lost market share to Angola and Nigeria.

And of course the pressure on Saudi Arabia is going to build as Iran ramps up exports. Iran's objective will be to recover lost economic ground now that sanctions have been lifted, even if this means driving global oil prices lower. With Iranian production costs as low as $1.7/bbl, Iran is in a strong position to win more market share.

There is another reason to believe that oil producers in general will rush to maximise output, at the expense of the price of oil over the next few years, and that is the pivotal COP21 climate change deal in Paris last year. Saudi Oil Minister Ali Naimi last month described the deal as an 'existential' threat to oil demand.

And to stress again, the economic Supercycle is over. This will become more and more apparent to everyone, and so will be another motive for oil producers to intensify their market share battle. If prices are going to weaken anyway because of the end of the Supercycle, why not maximise production to win greater market share.

The energy world in general has changed for good. The sooner chemicals companies accept this the better, as they can build sensible scenario plans for the future.

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OPEC dies in Qatar Written by Vagif G. Sharifov from Trend News Agency 'Five brothers' versus 'seven sisters' More than half a century ago, five major oil producing countries - Iran, Iraq, Venezuela, Kuwait and Saudi Arabia - agreed to work together to deprive seven transnational companies - Exxon, RD / Shell, Texaco, Chevron, Mobil, Gulf Oil and BP - of unlimited influence on the oil market.

Later, the number of 'brothers' reached 13 and they organized OPEC, while the 'sisters' started to work independently from each other. OPEC had a great influence on the oil market for tens of years.

When there was a need to reduce or increase the oil prices, all hopes were pinned on the cartel.

The cartel's decisions were clear, its management was accurate and effective, the violation of oil production quotas was not critical for the market and everyone turned a blind eye to this.

This situation continued until the 2000s, when OPEC's innovative price mechanism began to shake the market, intensified the speculations, began to sow discord among the participants and led to significant violations of quotas.

The oil prices were dropping to $16 per barreland increasing to $143 per barrel throughout 2000s.

The artificial overstatement in oil prices came to an end in the autumn of 2014, when the prices began to fall. The fall would have continued, if sometimes the rumors about saving the market are not pushed the prices up slightly. The negotiations in Doha were one of these popular rumors.

Salvation did not happen Several oil producing countries undertook the function to help with the support of Saudi Arabia, which has promised to consider what could be done. But the Saudis have always warned that they can't do and won't do anything, and together - means that all together. The intrigue expected from Doha was that how non-OPEC countries will succeed to agree with the cartel's member countries on freezing oil output at the level of January 2016. But the negotiations failed not due to a lack of consensus between OPEC and non-OPEC countries, which, incidentally, include the delegations of Azerbaijan, Russia, Kazakhstan, Bahrain, Oman and Mexico, but due to the fact that there was no agreement within the cartel, which 56 years ago undertook to save the world from the influence of 'Seven Sisters.'

Firstly, Iran refused to send any representatives to Qatar to participate in the meeting, motivating its decision by the fact that the country has been under sanctions for too long to freeze oil production now. The Saudis, in turn, demanded that absolutely all OPEC members join the initiative. Saying so, the Saudis meant those who didn't come to Doha, namely, Iran and Libya. Judging by the statements of the relevant ministers who arrived in Doha, no agreements at all were reached at the meeting.

For example, Russian Energy Minister Alexander Novak only said that the meeting in Doha became a significant event. Nigerian Oil Minister Emmanuel Ibe Kachikwu suggested to first settle everything within the OPEC before inviting other countries.

The next time the OPEC meeting will take place in Vienna in June, the Nigerian minister said, adding that the OPEC members will first agree among themselves before attracting the countries outside the cartel.

Thus, the meeting, which only worsened everything, showed that the OPEC is no longer relevant and there is an urgent need to create an alternative to the cartel. It is obvious that the results of Apr. 17 led to a six percent drop in the June oil futures on Apr. 18 - Brent crude at the opening of trading at the London Stock Exchange already dropped to $40 per barrel, while WTI crude fell by 6.8 percent to $36 per barrel.

In fact, the rescue plan in Doha could help prices increase. After freezing the production at the level of January and holding it until October, futures would begin increasing this Monday, but after an increase in demand in the third quarter (with the supplies at the level of the beginning of the first quarter), the prices would increase.

As a result, on average, we would have $55-$60 per barrel in 2016 versus $30-$35 per barrel, which perhaps we may obtain now. The speculations will only worsen the situation in terms of the unprecedented imbalance of supply and demand on the oil market because everyone has realized that there is nobody 'responsible for oil' any more. Thus, the failure during the Doha talks in fact revealed the death of OPEC. Nobody can hope for the growth of demand for crude oil as the IMF predicted the fall of the global economy this year. It is obvious that the weak economy generating weak demand for oil leads to a constant fall in prices in case of overproduction of crude oil. I wonder whether we see $9.1 per barrel again, as it was in December 1998.

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The Next Big Fight in Oil If Prices Rise Written by Keith Schaefer from Oil & Gas Investments Bulletin

As the oil price fell from $105/barrel in 2014 to $26/barrel in 2016, producers, service companies and banks/lenders worked very co-operatively to keep as many people employed and as much oil flowing as possible.

It has been a remarkably co-operative endeavour for the global energy industry.

I expect that to change to become a lot more cut-throat between these players as the oil price rises. There will be intense competition between the producers and service sector for every extra dollar that any increase in the oil price brings back into the energy complex.

Paul Kibsgaard, CEO of Schlumberger (NYSE:SLB) sent a Big Warning to that effect during a speech at the Scotia Howard Weil Conference in New Orleans recently.

Schlumberger is the world's largest oilfield service firm with 105,000 employees and operations in more countries than I can name. These guys have a lot of fingers on the pulse of what is really going on in the industry.

Kibsgaard notes that the oil producers are now doing the same three things they have done in every prior oil crash since the 1970s.

First, companies bring exploration spending to a near complete halt. Second, companies slow development spending of already discovered reserves. This is simple-less cash means less spending, and The Market will crucify any company increasing their debt now.

The Third Factor is the producers across the industry simultaneously squeezing the service industry for price concessions. This is a 'my pain is your pain' kind of thing.

Kibsgaard believes that it is this squeezing of the service industry that has created almost all of the so-called 'efficiency gains' that the producers have touted.

Source: Schlumberger Howard Weil Presentation The producers would have us believe that they have gotten that much better at drilling wells faster and making them more productive. You know, the graphs that look like this:

Kibsgaard believes that there is some truth in that, but most 'efficiencies' are really service cost reductions.

Kibsgaard's view is that as soon as activity levels in the industry pick up those pricing levels are headed higher. As the service costs rise, so too will the costs of drilling and completing a shale well.

The break-even costs being promoted by these companies might be true today, but as soon as activity heats up they are headed higher.

What he's saying is that investors should not expect the cash flows of oil producers to rocket up along with any increase in oil prices—because the service sector will get be getting a good chunk of that increased cash flow.

Let me share two conversations I very recently had on costs with Canadian management teams, one from the service sector and one from a producer (I host my own conference calls with management teams on a regular basis and provide transcripts to subscribers).

From the service company executive: 'I think when the (oil) market comes back it's likely not realistic...that the current service costs that the operators are enjoying—and rightfully so—and telling investors how they lowered drilling and completion costs and lowered finding and development costs.

It's not what people think and it's not guys in the field all over the place making $300,000 working half the year. It's guys making decent wages but they have skills and experience that justifies what they are paid...I don't think there is too much more room to go down.'

Now here's the producer executive: 'I find in Western Canada we, as industry, haven't made the adjustments there that are necessary. There is a lot of room to go in those service costs. I know those guys won't tell you but there is a lot of fat there that needs to be trimmed yet. I've had discussions with Presidents of those companies that they need to change.

'For example, I get on a plane and go to Toronto and its 20% full of oil field workers.

How is it at $30 oil that we can afford to fly people back and forth to Eastern Canada? So there is one example and I can go on with about 8 or 10 but I'd still be talking here at lunch if I rattled them all off.'

Thems fightin' words.

As an aside, Kibsgaard had one other major point in his talk-that the industry has not found any efficient new way to get oil out of the ground cheaply this century. Shale didn't work because of efficiencies he says-it worked because the industry threw hundreds of billions of low cost debt at it to make it work.

The yellow line in the slide below from Kibsgaard's presentation shows the massive amount of dollars that were thrown at oil and gas development in recent years. The increase in spending is incredible.

Source: Schlumberger Howard Weil Presentation The slide shows capex spending going from $100 billion in the year 2000 to nearly $700 billion in 2014. Yet with a sevenfold increase in spending the rate of global production growth really hasn't strayed from its gentle long term rise.

Very high (and for a while stable) oil prices combined with incredibly low interest rates funded all of this spending. Yes the innovation was important, but without that incredible surge in spending the shale boom would not have turned global oil markets upside-down.

Money made it happen. Lots of money.

And as Kibsgaard notes in his presentation:

'The fact remains that the industry's technical and financial performance was already challenged with oil prices at $100/bbl, as seen by the fading cash flow and profitability of both the IOCs and independents in recent years' The point of Kibsgaard's presentation was to say that the industry does not have a cost-effective solution to develop increasingly complex hydrocarbon resources.

EDITORS NOTE-I do own some oil producers, but my biggest position is in an offthe-beaten-track energy stock that pays me a steady-and increasing-dividend. I make $3500 a month off this beauty-the symbol and name of this stock is right HERE.

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