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THE above chart shows the extent to which this year's oil-price rally has been led by futures markets. What is significant, though, is that futures activity seems to have plateaued.

Sure, futures activity could easily go the other way again, driving prices significantly above the $50/bbl level. But barring a decision by the US Federal Reserve to once again step away from interest rate rises and China further loosening the credit tap, it is hard to see why the speculators would want to go deeper into bull territory. The market remains heavily distorted by the speculators, and so first and foremost you must analyse futures activity before you then look at physical supply.

Right now, I would argue that the Fed looks set on raising interest rates again in June or July. And in China, credit growth contracted again in April. I believe this indicates that economic reforms are 
gathering pace again.

As for the real supply and demand of oil, you should have been asking yourselves two questions throughout this rally: Shortages? What Shortages?

I'll deal with the Fed, China, and today' crude supply position in more detail later on. First of all, though, here is some historical context behind the role that financial markets have played in determining the oil price over the last seven years.

China, Jobs and Economic Stimulus

I believe that that the 2009-2014 rally in crude prices was driven by the fall in the value of the US dollar, thanks to the Fed's ultra-low interest rate policies. This forced hedge funds and pension funds etc. to seek an alternative 'store of value'. This store of value was oil and other commodities.

What seemed to justify this alternative store of value was China's parallel decision to conduct the biggest economic stimulus programme in global economic history, which cushioned the country from the impact of the Global Financial Crisis. It was all about preserving jobs for the Chinese leadership of the time. They didn't care about anything else, including the long term fundamentals of supply and demand as overinvestment poured into manufacturing and real estate. To give you an idea of the scale of what I am talking about, China increased lending by $10 trillion in 2009, when its nominal GDP was only $5 trillion. Lending was an astonishing $18 trillion higher by 2013.The long term economic benefits of this extraordinary rise in credit didn't worry the financial speculators. Of course not. It is not their job be worried about the long term. But other people who should have known better, including CEOs of some chemicals companies, who started talking about a 'new paradigm' of a rising middle class in China who would very soon be as rich as the middle classes in the West. This not only justified and underpinned the rallies in oil and commodity prices - but crucially also added further momentum to the rallies.

As this paradigm became the new consensus, the shale-oil industry took off in the US - aided also by the availability of cheap financing thanks to the Fed's interest-rate policies. Petrochemicals projects in the US, and elsewhere, were also sanctioned on the theory that China - and emerging markets growth in general - had entered this new paradigm.

It all went very badly wrong from September 2014, when it became apparent that Chinese economic stimulus 
had, after all, been unsustainable. Crude markets belatedly woke up to the notion that China's stimulus had left behind vast domestic oversupply in manufacturing and real, estate, and so a serious bad debt problem. The scale of China's environment crisis, made much worse by this overinvestment, was also recognised.

What made people wake up to these long-standing realities was that China's new political leaders admitted the scale of the problems - and, more importantly, they reversed course. They started reducing credit growth, and so the Chinese bubble began to dramatically deflate. Credit growth began to decline from January 2014. And here is another extraordinary number: In 2015, growth in credit was no less than $4 trillion lower than in 2014.

Back To The Future: Q1 2016

After the January 2016 collapse in oil prices and equity markets, the US Federal Reserve got cold feet. It began to back away from further interest rate rises, on the belief that weak crude and equities etc. meant that US economy was in too perilous a condition to take that risk. This was the signal sent to the oil speculators: The dollar was going to be weaker for longer than they had expected, and so it was time to get back into crude as an alternative store of value. This also led to recovery in other commodity markets, including iron ore.

What once again added further momentum to the rally was China's decision to loosen credit, which grew
by some 58% in Q1 over the first quarter of 2015. The detail didn't matter here. All that mattered to the crude-market speculators was the wider belief that China had, somehow, turned the corner. The renewed economic stimulus created the erroneous idea that China could spend its way out of trouble.

Now, though, thanks to stronger US GDP growth and continued robust jobs growth, Fed chairman Janet Yellen has indicated that 
two to three interest rate rises could, be on the cards later this year - with the first hike possibly in June or July.

And in China, credit growth fell in April. Total social financing 
plunged to 751 billion yuan during month compared with 2.34 trillion yuan in March.

Any sensible analyst would have told you that China's Q1 rise in lending was unsustainable - and that, of course, it was a drop in the ocean compared with the $4 trillion of credit withdrawn from the economy in 2015.

What told you it was unsustainable was that this represented another example of a victory for the short-term thinkers who in China, who prefer to prop-up immediate growth rather than deal with the longer-term issues. But you also had to bet that the reformers would reassert control - and, indeed, this has happened. In this particular instance, 
local governments temporarily gained the upper hand because of their struggle to cover their liabilities.

The end result - and may have already seen early signs of this in the above chart - could well be speculators switching back to the US dollar, as is strengthens - away from their alternative stores of value.

Actual Supply And Demand of Oil Itself

Last is not meant to be least. Of course, this matters. But in all the noise created by the speculators, the sound made by the data on physical production, storage and demand can sometimes be impossible to hear.

Take last year's oil-price rally as an example. Remember how we kept being told that the US rig count was falling? This took Brent from $45.19/bbl in mid-January to $69.63/bbl on 8 May.

Meanwhile, US shale oil producers continued to push the innovation envelope on cost reductions. Each rig in operation had also become much more productive. The 
practice of 'fracklogging' - storing oil in rocks ready to be fracked when prices recovered - also increased. And thanks to stronger futures prices, the shale oil industry was able to take out new hedges. This put them in the position to be able to sell at lower prices in the physical market because they had locked higher futures returns. Saudi Arabia also stuck with its market share strategy, whilst the global economy remained weak. This all led to the fall in oil prices during H2 2015.

The physical justification for today's rally is on even more shaky ground.

We were first told that there would be a production freeze agreement at the April Doha meeting. 
I never believed that this on the cards - and, of course, it didn't happen.

We did then, however, see a dramatic decline in production as a result of wild fires in Canada, attacks on Nigerian pipelines and more upheavals in Iraq. But I think that this was seized upon by markets whilst they overlooked some signs of long supply elsewhere. And, of course, this decline could well prove to be temporary.

Signs of long supply elsewhere includes oil in storage. Global oil stockpiles, including floating storage, have increased for the last ten consecutive quarters, according to this 
Hellenic Shipping News article, which adds:

It is estimated that almost 9% of the global VLCC fleet is currently booked for floating storage, which is a 40% increase in tankers by number since December. Reuters reported that at least 40 laden VLCCs anchored off Singapore as floating storage, storing estimated volumes of up to 47.7m bbl, thought to be the highest level in at least five years. 

Crucially, also the contango is narrowing. Last week, the one-month arbitrage on Brent in floating storage was -$0.48/bbl, while the 12-month arbitrage was at -$6.11/bbl, implying there was no profit incentive to store oil on ship. Storage costs are a minimum of $0.74/bbl, and so there has to be a risk of destocking.

Iran is also raising production. By the summer its exports are expected to rise a further 200,000 bbl/day to reach 2.2m bbl/day the middle of this summer.

And nobody should be surprised over reports that the US rig count has stopped declining, with early signs that the rig count may actually increase.The US is the world's new 'swing producer'. The inventory of drilled but uncompleted US wells 
has been building, driven by companies with contracted drilling services. Ccompanies have merely postponed, rather than cancelled, completion of wells. This could add 400,000 bbl/day to supply.

Let's not forget yesterday's OPEC meeting. There was again, of course, 
no agreement to freeze, never mind cut, production.

As for demand, the summer lull season in the northern hemisphere, when many people take their holidays, is set to occur in August and July.

If this market turns, those who want to short oil have plenty of physical ammunition to support their positions.

John Richardson from ICIS

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Your Weekly Update: 18 - 22 March 2019

Market Watch

Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b

  • Global crude oil prices slipped at the start of the week, as OPEC and its OPEC+ allies met in Azerbaijan to discuss the state of the club’s oil output cuts
  • Crude oil prices had risen prior as on speculation that the OPEC+ group would extend its supply deal, but this was dashed when OPEC+ instead decided to defer a decision until June, scrapping a planned OPEC extraordinary meeting in April because it was ‘too soon to make a decision on extending oil-supply cuts’
  • Observed friction between Russia and Saudi Arabia over the cuts could be behind the delay; Saudi Energy Minister Khalid al-Falih is said to be in favour of continue supply reduction through 2019 while his Russian counterpart Alexander Novak said that uncertainty over Venezuela and Iran would ‘make it difficult’ to decide until May or June
  • Other OPEC members have also not expressed any more willingness to extend the cuts, and Saudi Arabia seems to be unusually focused on a united front, rather than strong-arming the rest of the gang to its own aims
  • Some reprieve could be coming for OPEC, as the US Energy Information Administration trimmed its 2019 output forecast by 110,000 b/d to 12.3 mmb/d, seeing a scale-back in smaller shale plays and the US Gulf of Mexico
  • Echoing this, the US active rig count declined for a fourth consecutive week, following up a 9 and 11 rig drop with the net loss of a single oil rig
  • A better prognosis on demand leading into the northern summer and faith that OPEC+ will continue to work towards preventing a major crude surplus from returning should keep crude prices trending higher. We are looking at a range of US$66-68/b for Brent and US$58-60/b for WTI

Headlines of the week

Upstream

  • Eni has announced a major oil discovery in Angola’s Block 15/06, with the Agogo prospect joining the Kalimba and Afoxé discoveries, adding some 450-650 million barrels of light oil in place to the block
  • ExxonMobil has delayed its US$1.9 billion, 75,000 b/d Aspen oil project as Canada’s Alberta province continues to grapple with the pipeline bottleneck that has caused a glut of production trapped in the inland province
  • Lukoil had hit a new milestone with the Vladimir Filanovsky field, which has now reached 10 million tons of crude oil supplied through the Caspian Pipeline Consortium (CPC) system, transporting oil to the Black Sea for transport
  • ExxonMobil is looking to reduce field costs in its Permian Basin assets to about US$15/b, a highly-competitive target usually only seen in the Middle East
  • Eni and Qatar Petroleum have agreed to a farm-out agreement that will allow QP to take a 25.5% interest in Mozambique’s Block A5-A, joining other partners Sasol (25.5%) and Empresa Nacional de Hidrocarbonetos (15%)
  • Successive industrial action strikes have begun in the UK, affecting the Shetland Gas Plant and Total Alwyn, Dunbar and Elgin platforms in the North Sea
  • ADNOC has begun planning for an output drive at its Umm Shaif field, which would increase output at the giant field to 360,000 b/d

Midstream & Downstream

  • Shell is planning to restart the Wilhelmshaven refinery in Germany through a deal with terminal firm HES, which will re-convert the existing tank farm into a 260 kb/d refinery that will focus on producing IMO-mandated low sulfur fuels
  • Petronas is offering first oil products cargos from its 300 kb/d RAPID refinery in April, ahead of planned full commercial production in October 2019
  • Lukoil is now planning to invest some US$60 million in its 320 kb/d ISAB refinery in Augusta, Italy to produce high-quality, low-sulfur fuels to meet IMO standards, instead of selling it as previously considered in 2017
  • The Ugandan government has approved the technical proposal for the country’s first refinery in Kabaale, which will run on crude from the Albertine rift basin
  • Kenya expects to have the Lamu crude export terminal operational by the end of 2019, syncing with the start of Tullow Oil’s Kenyan oilfields

Natural Gas/LNG

  • The UK Onshore Oil and Gas body has published updated figures for UK onshore shale potential based on three test sites in north England, estimating that productivity could be at 5.5 bcf per well leading to annual gas production reaching 1.4 tcf by the early 2030s
  • Eni’s winning streak in Egypt continues, announcing a new gas discovery in the Nour 1 New Field Wildcat, which join its existing assets under evaluation there
  • Conrad Petroleum’s development plan for the Mako gas field in Indonesia has been approved by Indonesian authorities, paving way for development to start on the field with its estimated 276 bcf of recoverable resources
  • Ventures Global LNG is planning to double the capacity of its LNG projects – including the Calcasieu Pass and Plaquemines LNG sites in Louisiana – from 30 mtpa to a new 60 mtpa, having already booked all output from Calcasieu
  • Darwin LNG is set to choose the source of its backfill gas by the end of 2019, with the Barossa field more likely to be taken than the Evans Shoal field
March, 22 2019
Technology may be a game changer for future oil supply

Risk and reward – improving recovery rates versus exploration

A giant oil supply gap looms. If, as we expect, oil demand peaks at 110 million b/d in 2036, the inexorable decline of fields in production or under development today creates a yawning gap of 50 million b/d by the end of that decade.

How to fill it? It’s the preoccupation of the E&P sector. Harry Paton, Senior Analyst, Global Oil Supply, identifies the contribution from each of the traditional four sources.

1. Reserve growth

An additional 12 million b/d, or 24%, will come from fields already in production or under development. These additional reserves are typically the lowest risk and among the lowest cost, readily tied-in to export infrastructure already in place. Around 90% of these future volumes break even below US$60 per barrel.

2. pre-drill tight oil inventory and conventional pre-FID projects

They will bring another 12 million b/d to the party. That’s up on last year by 1.5 million b/d, reflecting the industry’s success in beefing up the hopper. Nearly all the increase is from the Permian Basin. Tight oil plays in North America now account for over two-thirds of the pre-FID cost curve, though extraction costs increase over time. Conventional oil plays are a smaller part of the pre-FID wedge at 4 million b/d. Brazil deep water is amongst the lowest cost resource anywhere, with breakevens eclipsing the best tight oil plays. Certain mature areas like the North Sea have succeeded in getting lower down the cost curve although volumes are small. Guyana, an emerging low-cost producer, shows how new conventional basins can change the curve. 


3. Contingent resource


These existing discoveries could deliver 11 million b/d, or 22%, of future supply. This cohort forms the next generation of pre-FID developments, but each must overcome challenges to achieve commerciality.

4. Yet-to-find

Last, but not least, yet-to-find. We calculate new discoveries bring in 16 million b/d, the biggest share and almost one-third of future supply. The number is based on empirical analysis of past discovery rates, future assumptions for exploration spend and prospectivity.

Can yet-to-find deliver this much oil at reasonable cost? It looks more realistic today than in the recent past. Liquids reserves discovered that are potentially commercial was around 5 billion barrels in 2017 and again in 2018, close to the late 2030s ‘ask’. Moreover, exploration is creating value again, and we have argued consistently that more companies should be doing it.

But at the same time, it’s the high-risk option, and usually last in the merit order – exploration is the final top-up to meet demand. There’s a danger that new discoveries – higher cost ones at least – are squeezed out if demand’s not there or new, lower-cost supplies emerge. Tight oil’s rapid growth has disrupted the commercialisation of conventional discoveries this decade and is re-shaping future resource capture strategies.

To sustain portfolios, many companies have shifted away from exclusively relying on exploration to emphasising lower risk opportunities. These mostly revolve around commercialising existing reserves on the books, whether improving recovery rates from fields currently in production (reserves growth) or undeveloped discoveries (contingent resource).

Emerging technology may pose a greater threat to exploration in the future. Evolving technology has always played a central role in boosting expected reserves from known fields. What’s different in 2019 is that the industry is on the cusp of what might be a technological revolution. Advanced seismic imaging, data analytics, machine learning and artificial intelligence, the cloud and supercomputing will shine a light into sub-surface’s dark corners.

Combining these and other new applications to enhance recovery beyond tried-and-tested means could unlock more reserves from existing discoveries – and more quickly than we assume. Equinor is now aspiring to 60% from its operated fields in Norway. Volume-wise, most upside may be in the giant, older, onshore accumulations with low recovery factors (think ExxonMobil and Chevron’s latest Permian upgrades). In contrast, 21st century deepwater projects tend to start with high recovery factors.

If global recovery rates could be increased by a percentage or two from the average of around 30%, reserves growth might contribute another 5 to 6 million b/d in the 2030s. It’s just a scenario, and perhaps makes sweeping assumptions. But it’s one that should keep conventional explorers disciplined and focused only on the best new prospects. 


Global oil supply through 2040 


March, 22 2019
ConocoPhillips vs PDVSA - Round 2

Things just keep getting more dire for Venezuela’s PDVSA – once a crown jewel among state energy firms, and now buried under debt and a government in crisis. With new American sanctions weighing down on its operations, PDVSA is buckling. For now, with the support of Russia, China and India, Venezuelan crude keeps flowing. But a ghost from the past has now come back to haunt it.

In 2007, Venezuela embarked on a resource nationalisation programme under then-President Hugo Chavez. It was the largest example of an oil nationalisation drive since Iraq in 1972 or when the government of Saudi Arabia bought out its American partners in ARAMCO back in 1980. The edict then was to have all foreign firms restructure their holdings in Venezuela to favour PDVSA with a majority. Total, Chevron, Statoil (now Equinor) and BP agreed; ExxonMobil and ConocoPhillips refused. Compensation was paid to ExxonMobil and ConocoPhillips, which was considered paltry. So the two American firms took PDVSA to international arbitration, seeking what they considered ‘just value’ for their erstwhile assets. In 2012, ExxonMobil was awarded some US$260 million in two arbitration awards. The dispute with ConocoPhillips took far longer.

In April 2018, the International Chamber of Commerce ruled in favour of ConocoPhillips, granting US$2.1 billion in recovery payments. Hemming and hawing on PDVSA’s part forced ConocoPhillips’ hand, and it began to seize control of terminals and cargo ships in the Caribbean operated by PDVSA or its American subsidiary Citgo. A tense standoff – where PDVSA’s carriers were ordered to return to national waters immediately – was resolved when PDVSA reached a payment agreement in August. As part of the deal, ConocoPhillips agreed to suspend any future disputes over the matter with PDVSA.

The key word being ‘future’. ConocoPhillips has an existing contractual arbitration – also at the ICC – relating to the separate Corocoro project. That decision is also expected to go towards the American firm. But more troubling is that a third dispute has just been settled by the International Centre for Settlement of Investment Disputes tribunal in favour of ConocoPhillips. This action was brought against the government of Venezuela for initiating the nationalisation process, and the ‘unlawful expropriation’ would require a US$8.7 billion payment. Though the action was brought against the government, its coffers are almost entirely stocked by sales of PDVSA crude, essentially placing further burden on an already beleaguered company. A similar action brought about by ExxonMobil resulted in a US$1.4 billion payout; however, that was overturned at the World Bank in 2017.

But it might not end there. The danger (at least on PDVSA’s part) is that these decisions will open up floodgates for any creditors seeking damages against Venezuela. And there are quite a few, including several smaller oil firms and players such as gold miner Crystallex, who is owed US$1.2 billion after the gold industry was nationalised in 2011. If the situation snowballs, there is a very tempting target for creditors to seize – Citgo, PDVSA’s crown jewel that operates downstream in the USA, which remains profitable. And that would be an even bigger disaster for PDVSA, even by current standards.

Infographic: Venezuela oil nationalisation dispute timeline

  • 2003 – National labour strikes cripple Venezuela’s oil industry
  • 2005 – Hugo Chavez begins a re-nationalisation drive
  • 2007 – Oil re-nationalisation, PDVSA to have at least 50% of all projects
  • 2008 – ExxonMobil and ConocoPhillips launch dispute arbitration
  • 2012 – ExxonMobil awarded damages from PDVSA
  • 2014 – ExxonMobil awarded damages from government of Venezuela
  • 2018 – ConocoPhillips awarded damages from PDVSA
  • 2019 – ConocoPhillips awarded damages from government of Venezuela
March, 21 2019