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Last week in World oil:

Prices

  • Oil prices got a boost, within striking distance of US$60/b, as major producers say that the global supply glut is shrinking as strong demand creates a rebalancing, as well as threats by Turkey to cut off Kurdistan’s only pipeline outlet for its crude oil over its independence referendum.

Upstream

  • As Lebanon seeks to join Cyprus, Egypt and Israel in exploiting potential offshore oil and gas resources, its Parliament has approved a law outlining tax revenue structure for oil companies, as Lebanon prepares for its first offshore auction. Five offshore areas will be offered on October 12, to be taxed at 20% income tax under the new law; 46 companies have signed up for the auctions, including ExxonMobil, Shell, Eni and Total.
  • A third consecutive week of decline for US drillers, as the loss of five oil rigs was only partially offset by the gain of four gas rigs. Losses were mainly in Eagle Ford, while restarts begin in the Permian.

Downstream & Midstream

  • Phillips 66 Partners LP – the master limited partnership that operates pipelines in the Bakken basin – will buy midstream assets from its parent Phillips 66 in a US$2.4 billion deal. Under the deal, Phillips 66 Partners will acquire a 25% interest in the Dakota Access and Energy Transfer Crude Oil Company LLCs – totalling 530 kb/d of crude oil pipeline capacity. With both companies listed separately, this leaves Phillips 66 free to concentrate on refining operations, and the MLP on distribution.
  • After Harvey and Irma – and with Maria on its way – the resulting gap in Gulf refining production is proving to be a boon for European diesel exports to Latin America. Trade sources indicate that some 600,000 tons of diesel and heating oil will be heading to Brazil and Argentina from Europe, as the fuel hungry region finds volumes from its traditional sources in the US Gulf and Caribbean withdrawn. This is some three times the usual trade, and is expected to continue until end October.

Natural Gas and LNG

  • Cheniere has officially requested permission from the US Federal Energy Regulatory Commission to place the fourth train at its Sabine Pass LNG export facility in Louisiana into service. First LNG was achieved at Train 4 in July, checking off all environmental and safety requirements. Cargo commissioning has already begun, bringing Cheniere close to its ambition of six trains at Sabine Pass, each with 4.5 mtpa capacity.
  • Algeria’s Sonatrach is aiming to boost gas output at its Hassi Messaoud field by 10 mcm/d and at its Rhourde el Baguel oil field by 6 mcm/d. This attempt to up output comes as Sonatrach seeks buffer against fluctuating oil prices to stabilise government revenues. The additional volumes will come on by next year, targeted as exports to Europe.
  • Canada’s Veresen is trying once again to gain US federal approval for its Jordan Cove LNG export plant in Oregon. The project has been rejected twice under the Obama administration, but the Trump presidency might be friendlier to the US$10 billion, 7.8 mtpa project targeting Asia. Meanwhile, the Eagle LNG Maxvillesmall-scale LNG facility in Florida has been approved, with capacity for some 21 mtpa of exports.

Last week in Asian oil

Upstream

  • Saudi Aramco is moving ahead with the development of its Safaniyah, Marjan, Zuluf and Berri oilfields, handing out more than US$1.5 billion in three major offshore contracts as it continues on a US$300 billion investment plan through 2027. The technical contracts precede major development plans for the fields, which include the sixth phase of the giant Safaniyah field (with 37 billion barrels of heavy oil), a US$3 billion expansion of Marjan and a boost in production at Berri by 200 kb/d.
  • India’s ONGC has announced a ‘good’ offshore find near its Mumbai High offshore fields that could hold some 20 million tons of oil equivalent. Though small by international standards, it is a large discovery in India terms, with the WO 24-3 well in a different play than neighbouring Mumbai High fields, potentially opening up a new area of exploration.

Downstream & Midstream

  • Sri Lanka is in talks with the two Chinese companies to build a US$3 billion oil refinery in the new Chinese-build port of Hambantota. The proposed 115 kb/d is the second of two planned refineries in Sri Lanka, to ease pressure on the aging CPC refinery. The first, a 100 kb/d site planned with Indian Oil in Trincomalee is export-oriented, while the new Chinese site will serve both domestic needs and produce some exports.
  • A jet fuel crisis continues to brew in New Zealand, as over 200 flights have been cancelled from Auckland – the country’s largest city – as the sole, private-owned pipeline delivering jet fuel to the airport from NZ’s sole refinery was damaged for months without being fixed.

Natural Gas & LNG

  • The government of Papua New Guinea will be selling off its stake in Oil Search, as it seeks to pay off some US$1 billion in debt. With stakes in PNG’s massive Elk and Antelope gas fields, Australia’s Oil Search has a major presence in PNG, though it was beaten out by ExxonMobil to acquire InterOil earlier this year. The PNG government holds a 9.8% stake in the company, which will be sold by UBS and JP Morgan at a floor price of A$6.55 per share.
  • Bangladesh signed its fourth and fifth natural gas import deals last week, with Indonesia and Gunvor. Under the preliminary long-term agreement with Indonesia’s Pertamina, Petrobangla will take in at least 1 million mtpa of LNG from Indonesia, while the contract with Gunvor is for a mixture of spot, short-term and medium-term volumes, beginning in 2018. Bangladesh has also signed a contract with Qatar to import some 2.5 mtpa of LNG from RasGas over a 15 year period for cooking fuel.
  • China’s CNOOC is reviving a plan to build an LNG import terminal in Binhai, Jiangsu. Initially proposed in 2010, the US$1.7 billion project has been endorsed by CNOOC’s investment committee as China’s appetite for LNG continues to grow. The project has an initial capacity of 3 mtpa of LNG, with a potential phase doubling capacity to 6 mtpa. Associated power generation facility will be included in the project as well.
  • Japan’s Mitsui OSK Lines is aiming to buy a stake of at least 26% in the Swan Energy FSRU off the coast of Jafrabad in Gujarat, Insia. With capacity for 5 mtpa and startup expected in 2020, the FSRU is being built by Hyundai Heavy Industries and chartered to Swan Energy by Mitsui OSK. The Japanese company will also be taking an 11% stake in Swan LNG, the Swan Energy subsidiary that will manage terminal and port facilities.

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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