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Remember the shale gale and Saudi America? The scale of those outlandish delusions has now dwindled to plays in a few counties in West Texas and southeastern New Mexico. Saudi Permian.

It’s a race to the bottom as investors double down on the tight oil companies that can still tell a growth story. Permian-weighted E&P companies are the temporary darlings of Wall Street as other tight oil plays have lost their luster.


A Silly Price Rally: Catch-22

We are in the middle of a truly silly price rally. Other rallies of 2015 and 2016 took place despite substantial production surpluses and too much inventory. Then, there was some hope that higher prices might result if over-production could be brought under control. Now, the world’s production and consumption are near balance but oil prices remain mired in the $40 to $50 per barrel range.

This current rally will end badly because there is something more fundamental keeping prices low. Despite repeated assurances from IEA and EIA that demand growth is strong, it is not strong enough to draw down outsized global inventories.

Hope for an OPEC production freeze at next month’s meeting in Algiers is the main factor driving this rally. The problem is that the world liquids market is as close to balance as it ever gets—over-supply has been less than 0.5 million barrels per day for the last two months. Oil prices were more than $100 per barrel at similar or greater production surpluses in 2013 and 2014.

In 2015, when the average production surplus was 2 million barrels per day, it was a different story. Over-production is not the problem now as it was then. If OPEC freezes production, it won’t make any difference.

Inventories exceed all historical levels. The world remains over-supplied because there is too much oil in inventory.

As long as oil prices are are range-bound between about $40 and $50 per barrel, it makes more sense to store oil than to sell it. The carrying cost of storage is less than what can be made by rolling futures contracts over each month. Inventories will stay high until prices break out of their current range but outsized inventories make that impossible. Catch-22.


Four Oil-Price Cycles in 2015 and 2016

There have been four oil-price cycles in 2015 and 2016–the first three each lasted approximately 6 months. Each new cycle began with high price volatility that fell as price peaked. We are currently in the upward arc of Cycle 4.

The oil-price volatility index has fallen to levels similar to when prices peaked during the last cycle suggesting that current WTI futures prices just above $48 per barrel may already be near the peak for this cycle. Prices may increase into the low-$50 per barrel range as they did in June before falling again.

The latest cycle began when NYMEX futures prices fell below $40 per barrel in early August. In the succeeding two weeks, they have climbed to more than $48. A factor beyond a possible OPEC freeze is the weakened U.S. dollar because of expectations that the Federal Reserve Bank will not raise interest rates at least until December. The value of the dollar against other major currencies has fallen 3% over the last month (36% annualized). WTI futures prices have increased 22% since August 1.

A third factor driving the current price rally is long-term concern about supply because of under-investment in oil development projects and exploration since the oil-price collapse. Recentstatements by the International Energy Agency that demand may outpace supply in the next few years underscored that anxiety.

Figure 3 shows that oil prices appear to be range-bound between about $40 support and $51 per barrel resistance levels. The upper boundary is largely controlled by record-breaking volumes of U.S. and world crude oil inventories and the fact that producers add rigs and production with each upward swing in oil prices.

The 200-day moving average of NYMEX futures prices suggests similar range boundaries of about $38 and $52 per barrel.


Staggering Inventories

This market looks for any excuse to raise prices.  Every price upswing is seen by some as the beginning of a return to oil prices above $70 per barrel. We seem to selectively forget that the staggering inventory levels of crude oil make this impossible until those volumes are drawn down substantially. Oops.

U.S. crude oil inventories fell 2.5 million barrels this week but have increased a net 1.6 million barrels over the last month during what is supposed to be de-stocking season.

Storage volumes are 57 million barrels more than at this time in 2015 and are 143 million barrels higher than the 5-year average. This is definitely not a basis for a sustainable oil-price rally. Until inventories are drawn down by at least another 125 million barrels, a recovery to somewhere approaching mid-cycle 2014 levels of about $80 per barrel is technically impossible.


The Permian Basin Dominates Rig Count Increases

Five new horizontal rigs were added last week to drill tight oil objectives in the Permian basin and 12 rigs were added the previous week. Only 1 rig was added in the Bakken play after losing 2 rigs a week ago. No rigs were added in the Eagle Ford after losing 1 rig the previous week. More capital is being spent in the Permian basin than in all the other plays put together.

Overall, 67 tight oil rigs have been added since early June. Forty eight of those are in the Permian basin, 5 in the Bakken and 6 in the Eagle Ford play. Four rigs were added in the Niobrara, 3 in the Granite Wash and 1 in Other. Rig count increases began as oil prices peaked above $50 per barrel in early June and continued through the slump toward $40 prices before the latest upward swing to $48 per barrel.

Weekly changes in the Permian basin rig count are the leading indicator of capital flows and expenditures. Permian rig count is more responsive to capital flows than the other tight oil plays because there is more money available for Permian-weighted companies.

In late July, I wrote, “When prices fall and oil-price volatility increases, the floodgates of capital open. Every genius-investor wants to buy low and sell high. Rig count rises with fresh capital, production increases and oil prices fall.”

In fact, the Permian basin accounts for 64% of the total U.S. horizontal tight oil rig count.

This is curious because Permian production from the Bone Spring, Wolfcamp and Trend-Spraberry horizontal plays represents only 21% of total tight oil production.

It is even more curious because Permian basin tight oil proven reserves rank 42nd in the world just behind Denmark and Trinidad and Tobago based on the latest EIA data.

Some will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based on any reality-based interpretation of existing data.

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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