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Last week in World oil:

Prices

  • Crude prices remain stuck in their range – Brent at US$57/b and WTI at US$51/b – as swings in US inventories outweigh Middle Eastern geopolitical concerns, with little on to horizon to move the market. 

Upstream

  • Chinese major Sinopec is planning to exit Argentina, after losses and labour woes prompted it to put its oil assets on sale. Acquired in 2010 from Occidental Petroleum for US$2.45 billion, the acquisition was part of Sinopec’s drive to establish a portfolio of international upstream assets. However, a shaky political and economic situation in Argentina caused losses, and the oil and gas assets – mainly in the southern province of Santa Cruz – now have a price estimate of US$750 million-1 billion.
  • Uganda is quickly becoming a potential new African upstream bright spot, with Nigeria’s Oranto Petroleum recently signing two PSCs to explore around the Lake Albert basin. The Ngassa Shallow Play and Ngassa Deep Play are located within the Albertine rift basin where Uganda first struck oil in 2006; Uganda’s first domestic oil is expected in 2020.
  • Cote d’Ivoire has concluded four PSCs with Tullow Oil in a bid to jumpstart its fledgling upstream industry. Producing a mere 8 kb/d of oil and 200 mcf/d of gas, Cote d’Ivoire lags behind Senegal and Ghana, but is hoping that recent big finds in its neighbours hint at potential within its waters. State oil firm Petroci will hold 10% of each PSC.
  • US drillers cut active rig counts for the fourth time in five weeks, as price realities impact production plans. Eight rigs were removed from service last week – five oil and three gas – leaving the total active count at 928.

Downstream & Midstream

  • Another international joins the queue to exploit Mexico’s recently deregulated fuel retail industry, joining Shell, BP, ExxonMobil and Glencore. France’s Total is expanding its downstream presence in Mexico from specialty products to a full service station network, rebranding some 250 Mexico City-area GASORED group sites to the Total brand. The first site will be opened in late 2017, rolling out over 2018 and 2019. 

Natural Gas and LNG

  • More LNG this way comes. A week after Chevron began operations at Wheatstone, Russia’s Yamal LNG project in the Arctic confirmed that it will ship its first LNG cargo in November. Operated by Russia’s Novatek with France’s Total, China’s CNPC and the Silk Road Fund, Yamal will begin with two shipments in November, four in December, then ramp up to ten in 2018. The first cargoes were reportedly sold on the spot market.

Corporate

  • Indications are the Saudi Aramco’s planned IPO has hit some snags. Recent reports indicate that some delays are expected, with a two-stage IPO likely – floating in Riyadh by the end of 2018 and delaying the planned international portion until 2019. Some chatter on the market even suggests that Aramco may scrap the international portion altogether, replacing with a private share sale to select world sovereign funds and institutional investors.

Last week in Asian oil

Upstream

  • Malaysia’s Petronas has outlined its plans for the Bukit Tua field in Indonesia. Phase one of Bukit Tua came on stream in May 2015; phase two is currently underway and Petronas wants to expand into a phase three that will exploit the field’s Kujung horizon. Expansions will continue through July 2022, lifting production from its current peak rate of 20 kb/d of oil and 50 mmscf/d of gas. Petronas holds 80% of the PSC, with the remainder held by Pertamina.

Downstream & Midstream

  • CNOOC’s 200 kb/d refinery in Huizhou is ready for commissioning. Crude trial runs have been completed at the site in Guangdong, which is part of CNOOC’s Huizhou refining and petrochemical complex that represents the firm’s move downstream to compete with Sinopec and PetroChina. The focus of the complex is for both fuels and chemicals, with a 1.2 mtpa ethylene plant (a joint venture with Shell) due to be completed in Q12018.
  • From a loose and scrappy group, China’s independent refiners – the teapots – are increasing becoming more structured and united, as they face increasing criticism from Sinopec and PetroChina. After forming a crude buying alliance last year, six influential teapots – including Dongming, the country’s largest independent refiner – set up the Shandong Refining & Chemical Group last month, and has now bolstered it with a CNY33 billion (US$5 billion) fund. The joint fund will go to joint production, operation and investment plans, as well as lobbying efforts, to support the group’s refining capacity of 660 kb/d.
  • Once dismissed as a pipe dream, the private Pulau Muara Besar refinery planned by Hengyi Petrochemical in Brunei actually appears to be progressing to reality. The Chinese group has started up a trading office in Singapore, which will buy crude and trade fuel products produced at the 175 kb/d, US$3.4 billion project. Primarily a petrochemical play to support Hengyi’s fabric and industrial arms, the refinery will also produce a significant amount of gasoline, gasoil and jet fuel, which Hengyi has no internal use for. The company has also announced a US$12 billion second phase that will include expanding capacity to 280 kb/d and secondary units to produce some 1.5 mtpa of ethylene and 2 mtpa of PX.

Natural Gas & LNG

  • Bangladesh is striving ahead in its LNG ambitions, signing up for a third floating LNG project with Malaysia’s Petronas and China’s Hong Kong Manjala Power. Planned to be located at Kutubdia in Cox’s Bazaar, the 3.5 mtpa import terminal is planned for a 2019 start, just in time to replace Bangladesh’s dwindling natural gas production. The country’s first FSRU – a 3.75 mtpa facility off Moheshkhali in the Bay of Bengal – is expected to start up in 2018.
  • CNPC has started up its third natural gas pipeline servicing Shanghai, aiming to meet the growing demand for clean power generation fuel in the city. The new 88km pipeline connects the Rudong LNG receiving terminal in Jiangshu with Shanghai’s Chongming island, with a capacity of some 1.84 billion cbm per year.

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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