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Last Updated: June 22, 2017
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Last week in the world oil:

Prices

  • All the progress achieved since the OPEC supply quotas were agreed on have been undone, as crude prices fell to a seven-month low. With Brent at US$47/b and WTI at US$43/b, traders are concerned that rising production in Libya and Nigeria (exempt from the freeze), as well as in the US, have undermined OPEC’s ability to influence prices. With the glut growing and news of tankers increasingly being used as storage, there is little upside for crude prices now, so expect the decline to continue.

Upstream & Midstream

  • Deepwater seems to be back, as ExxonMobil signed off on the Liza field in Guyana. Together with partners Hess and CNOOC, the US$4.4 billion offshore project is the fifth deepwater project to be sanctioned this year, in part due to the attraction of its lower production costs. It marks a cautious return to upstream megaprojects after the price crash in 2015, in parallel with majors developing lower-cost shale sites as well. The first phase of Liza should pump 120 kb/d when it comes online in 2020.
  • Uganda has signed two production sharing agreements with Nigeria’s Oranto Petroleum that will see the first crude flow by 2020. Oil from the Ngassa Shallow and Ngassa Deep plays in the Albertine rift basin forms part of gross national recoverable reserves of 1.4-1.7 billion barrels. Landlocked Uganda is already working with Tanzania to build a heated pipeline to ship its crude internationally through the port of Tanga.
  • Six new oil rigs started up in the US last week, bringing the total number of oil rigs to 747 and total rigs to 933. In Canada, 27 new rigs started up last week as well, arresting the long slide in Canadian drilling sites.

Downstream

  • Mexico’s Pemex has begun to restart its 330 kb/d Salina Cruz refinery after Tropical Storm Calvin flooded the plant, breaking containment dams and triggering spills that halted the entire refinery. A fire that broke out killed a firefighter and injured nine workers has also been put out, allowing startup procedures to begin restoring the refinery to operation.

Natural Gas and LNG

  • While some central and southern European countries plan alternative gas routes, Austrian energy group OMV is considering reviving a plan to build a Black Sea pipeline to connect Russian Gazprom natural gas with the region. The plan is merely an outline at the moment, but will be an extension of the TurkStream pipeline currently being built that will connect to OMV’s Baumgarten gas hub and its 57 bcm/y capacity. Further south, Greece, Cyprus and Israel have jointly agreed to speed up their plans to develop a pipeline connecting Israel and Cyprus’ gas fields to the Mediterranean through a 2,000km pipeline linked to Greece and Italy. The new target completion date of 2025.
  • Shell and Qatar Petroleum have signed an agreement to jointly develop global LNG bunkering facilities. Combining Qatar’s vast LNG capacity and Shell’s bunkering expertise, the aim of the plan is to meet increasing demand for LNG as a bunker fuel, with Qatar Petroleum estimating that demand will reach 50 million tons per annum by 2030.

Last week in Asian oil

Upstream

  • As Chinese producers try to strike a balance between raising capex to boost domestic crude production with declining reserves, Chinese oil production fell to its lowest level on record in May. Production fell 3.7% y-o-y to 3.83 mmb/d, the lowest since the National Bureau of Statistics began publishing records in 2011. Producers like PetroChina are having to choose between cutting spending at rapidly declining fields like Daqing and Shengli, while raising spending elsewhere to help ease China’s increasing reliance on imported crude.

Downstream

  • China has issued a second round of crude oil import quotas. The overall number is higher than the entirety of allowances in 2016, but crucially, the allowance for teapot refineries is lower by some 17%. This is seen as an attempt by Beijing to exert control over a section of the refining industry that exploded last year, flooding the country with fuel.
  • Saudi Aramco’s relentless march into downstream continues, trying to secure footholds in key Asian markets to ensure captive demand for its crude. After Malaysia and China, Aramco is now talking with the Indian government to purchase a stake in the planned 1.2 mmb/d megarefinery to be build by the trio of state oil firms – Indian Oil, HPCL and BPCL – on the west coast. With little of its own crude to feed this planned site, India will need crude to run the refinery; and Saudi Aramco is happy to oblige, demanding a stake in what would be the world’s largest refinery.

Natural Gas & LNG

  • BP and Reliance in India have agreed to jointly invest up to US$6 billion to restart work in the country’s east coast gas blocks, where eight years of inertia have led to curtailed production. The money will be poured into developing 3 trillion cubic feet of natural gas, boosting production at the D6 block in the Krishna Godavari basin by 30-35 mcf/d by 2020. The BP-Reliance partnership was resuscitated after the government relaxed rules last year, allowing freedom in pricing and marketing gas in an attempt to attract investment into India’s dormant deepwater gas fields.
  • Japan’s JX Nippon Oil & Gas Exploration has commenced commercial gas production from the Layang field in Malaysia. Initial production of natural gas and condensate from the field offshore Sarawak is estimated at 12 kb/d, which will be piped together with gas from the Helang field to Petronas’ MLNG Tiga LNG plant in Bintulu, in which JX Nippon has a stake.
  • Faced with the departure of Chevron from its gas fields, Bangladesh’ state energy firm PetroBangla has inked an agreement with Swiss trader AOT Energy to secure LNG for the power-hungry nation. The LNG will be directed at the country’s first LNG terminal being built as an FSRU at Moheshkali island by Excelerate Energy. Another LNG terminal is also being planned, at Kutubdia Island with India’s Petronet LNG.
  • The capacity for the Abadi LNG project in Indonesia appears to be settled at 9.5 mtpa, with partners Inpex and Shell nearing agreement with Indonesia’s Energy and Mineral Resources Ministry. This would leave some 150 mcf/d of natural gas available for the domestic market to meet Indonesia’s domestic market obligation requirements. This would be almost four times the initial planned LNG capacity of 2.5 mtpa for Abadi, as Inpex itches to commercialise a discovery made in 1992. A smaller capacity of 7.5 mtpa is also being considered, which would leave 500 mcf/d leftover.

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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