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Last Updated: May 25, 2017
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Last week in the world oil:

Prices

  • As confidence grows that the world’s top oil exporters will agree to extend the OPEC supply cuts, crude oil prices have hit their highest point in a month. Brent started the week at nearly US$54/b, while WTI managed to break past the US$50/b level to settled at almost US$51/b.

Upstream & Midstream

  • First oil has begun to flow at Quad 204’s, BP’s new upstream project in the west of Shetland region in the UK. The Schiehallion and Loyal fields in the area were originally developed in the mid-1990s and are now part of the Quad 204 redevelopment project led by BP with co-venturers Shell and Siccar Point Energy. Some additional 450 million barrels of resources are expected to be unlocked, with production lasting to 2035, and highlights the potential of the UK to develop its Atlantic energy resources.
  • Even as crude prices see-saw, US oil production as proxied by rig activity shows no sign of stopping. Sixteen new oil and gas rigs started up last week – 8 apiece – including 2 offshore rigs to bring the US active rig count above 900 for the first time in almost two years.

Downstream

  • In the footsteps of BP and Glencore, ExxonMobil is now the latest firm to target Mexico’s downstream market. The US supermajor announced that it would be investing US$300 million to established a network of Mobil fuel station in the recently opened Mexican sector. BP was the first to stake a claim in Mexico, and has reported that its plan to open some 1,500 service stations has been more promising than expected, leading to an increase in investment. Trader Glencore has established a deal with Mexico’s Corporacion G500 SAPI to establish some 1,400 G500 Network-branded sites, creating even more competition.

Natural Gas and LNG

  • As upstream action in the eastern Mediterranean heats up, Greece is making another attempt to strike gas. With Israel’s Leviathan and Egypt’s Zohar giant gas discoveries establishing the Levant Basin as a natural gas powerhouse, Greece has invited ExxonMobil and Total to test for natural gas in areas south of Crete island and western Greece. Previous attempts to elicit interest in the blocks failed, but the recent gas discoveries have changed the upstream outlook for the area.
  • South Africa will be looking to issue its first shale gas exploration licences this September, with Shell, Falcon Oil and Gas and Bundu Gas & Oil likely to receive permission to drill for shale in the onshore Karoo basin. South Africa has historically dependent on offshore production for its gas, but is now turning to onshore opportunities as production dwindles and the country attempts to wean itself off coal as a power plant fuel.

Corporate

  • Saudi Aramco will be setting up a petrochemicals subsidiary, putting it in direct competition with Saudi chemicals giant SABIC. The potential change comes as Saudi Aramco attempts to diversify and strengthen its downstream operations ahead of its planned IPO, to create more broad-based operations to be palatable to investors. Aramco has plans to triple its current chemicals production to 34 million tons by 2030.

Last week in Asian oil

Downstream

  • Fresh off its tie-ups in Malaysia and India, Saudi Aramco has announced another mega refining project, this time in China. The joint venture between Aramco and state-owned China North Industries Group (Norinco) will see the world’s largest crude seller and world’s largest crude importer build a 300 kb/d oil refinery with a 1 million ton/year ethylene cracker in Liaoning. The move will deepen the ties between the two nations, as Saudi Aramco looks to lock up long-term supply for its crude through strategic downstream investments. The project is unusual, as Norinco is primarily a defence manufacturer, and could be a signal that China is serious about opening up competition in its energy industry.
  • To the surprise of no one, Vietnam’s second refinery has been delayed. The US$7.5 billion Nghi Son site has been delayed to 2018 from 3Q17, as the refinery faced some mechanical troubles in test runs. The delay means that Vietnam will remain heavily dependent on oil product imports, which Nghi Son was expected to ease.
  • China’s section of the East Siberia Pacific Ocean (ESPO) pipeline will be completed by 2018. As China expands its crude import options, the pipeline connecting the city of Mohe at the Russian border to the city of Daqing will pump some 15 million tons/year of Russian crude to China.

Natural Gas & LNG

  • Italy’s Eni has started gas production at Indonesia’s Jangkrik ahead of schedule. Ten offshore deepwater subsea wells have been connected to the new Jangkrik Floating Production Unit (FPU), with production expected to scale up to 450 million cubic feet per day. Processed gas will be delivered onshore via a 79km pipeline, connecting to the Kalimantan Transportation System to the Bontang LNG plant.
  • Malaysia’s Petronas has signed a MoU with Gas4Sea to collaborate and promote LNG as a cleaner maritime fuel. The move is in line with Petronas’ aim of diversifying its LNG business, with the deal signed through its shipping affiliate MISC. Gas4Sea comprises French natural gas company Engie, and Japanese shippers Mitsubishi and Nippon Yusen Kabushiki Kaisha. Bunker fuels have traditionally been heavy fuel oil, but efforts to promote cleaner fuels have led the shipping industry to consider gasoil and LNG as alternate fuels.
  • Another month and another shutdown at Chevron’s Gorgon LNG plant. The eighth outage since the project began in early 2016, Train 1 has been shut down for at least a month to replace to a faulty flow-measurement device. Outages have plagued the project but Gorgon is slowly finding its footing, starting up Train 3 in March 2017. Chevron will also be boosting capacity on Train 2 of its other Australian project, Wheatstone, as partner Woodside targets production growth of 15% per year through 2020.
  • China has successfully extracted natural gas from methane hydrate deposits mined deepwater. Trapped in ice-like chunks, gas is extracted and processed in a floating platform unit platform in the Shenhu area of the South China Sea. The successful extraction paves the way for a new revolution in energy that would help boost Chinese domestic gas production over the long run. Commercial development of the resource is still far away, with 2030 named as a target date.

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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
This Week in Petroleum
The United States exported 2 million barrels per day of crude oil in 2018 to 42 different destinations

In 2018, U.S. exports of crude oil continued to increase to 2.0 million barrels per day (b/d), up 846,000 b/d (73%) from 2017 (Figure 1). The number of destinations for U.S. crude oil exports also increased from 37 to 42. Volumes by destination changed significantly between the first and second halves of 2018.

Figure 1. U.S. crude oil exports (1920 - 2018)

The increase in U.S. crude oil exports was the result of increasing U.S. crude oil production and infrastructure changes. U.S. crude oil production increased 1.6 million b/d from 2017 to 10.9 million b/d in 2018, with the U.S. Gulf Coast—where more than 90% of U.S. crude oil exports depart from—producing 7.1 million b/d. The increased production is mostly of light, sweet crude oils, but U.S. Gulf Coast refineries are configured mostly to process heavy, sour crude oils. This increasing production and mismatch between crude oil type and refinery configuration causes more of the increasing U.S. crude oil production to be exported.

In early 2018, modifications were made at the Louisiana Offshore Oil Port (LOOP) in the Gulf of Mexico to enable the loading of vessels for crude oil exports. LOOP is currently the only U.S. facility capable of accommodating fully loaded Very Large Crude Carriers (VLCC), vessels capable of carrying approximately 2 million barrels of crude oil. After LOOP was modified to also allow exports, the increase in cargo scale led U.S. crude oil exports to surpass 2 million b/d for 25 weeks in 2018 compared with just 1 week in 2017. In addition to LOOP, other U.S Gulf Coast export facilities in and around Houston and Corpus Christi, Texas, have been investing in increasing the scale of U.S. crude oil export cargos.

In 2018, Asia was the largest regional destination for U.S. crude oil exports, followed by Europe, and, as in previous years, Canada was the largest single destination for U.S. crude oil exports. Canada received 378,000 b/d of U.S. crude oil exports, representing 19% of total U.S. crude oil exports in 2018. South Korea surpassed China to become the second-largest single destination for U.S. crude oil exports in 2018, receiving 236,000 b/d compared with China’s 228,000 b/d (Figure 2).

Figure 2. 2018 U.S. crude oil export destinations

However, the distribution of U.S. crude oil exports by destination varied significantly from the first half of 2018 to the second half. In the first half of 2018, the United States exported 376,000 b/d of crude oil to China, which made China the largest single destination for U.S. crude oil exports for that period. However, in August, September, and October of 2018, the United States exported no crude oil to China, and then in November and December it exported significantly less than in earlier months. In the second half of 2018, the United States exported 83,000 b/d of crude oil to China, a decrease of 294,000 b/d from the first half (Figure 3).

Figure 3. U.S. crude oil exports by destination (1H 2018 vs. 2H 2018)

In the summer of 2018, as part of ongoing trade negotiations between the United States and China, China temporarily included U.S. crude oil on a list of goods potentially subject to an increase in import tariffs. At the same time, the difference between the international crude oil benchmark Brent and the U.S. domestic price West Texas Intermediate (WTI) futures prices narrowed rapidly between June and July 2018. Brent prices went from $9 per barrel (b) higher than WTI in June to $6/b higher than WTI in July. The rapidly narrowing price discount of U.S. crude oils versus international crude oils and the potential for higher import tariffs caused Chinese buying of U.S. crude oil to slow.

Although U.S. crude oil exports to China slowed in the second half of 2018, exports to South Korea, Taiwan, Canada, and India increased significantly. U.S. crude oil exports to South Korea increased 247,000 b/d (222%) between the first and second half of 2018. U.S. crude oil exports to other destinations in Asia also increased, particularly to Taiwan, which rose 111,000 b/d (168%) in the second half of 2018 compared with the first half, and to India, which increased 86,000 b/d (97%) during the same period.

Despite the volume changes in U.S. crude oil destination between the first and second halves of 2018, the list of destinations has remained consistent over the past three years. Of the 27 destinations that took U.S. crude oil in 2016, the first year of unrestricted U.S. crude oil exports, 22 destinations did so again in 2017 and again in 2018 (Figure 4). Furthermore, few destinations appear to be one-time recipients of U.S. crude oil, other than those such as the Marshall Islands that were listed because of data collection methods and ship-to-ship transfers.

Figure 4. U.S. crude oil export destinations

U.S. average regular gasoline price increases, diesel price falls

The U.S. average regular gasoline retail price rose nearly 8 cents from the previous week to $2.55 per gallon on March 18, down 5 cents from the same time last year. The East Coast price rose nearly 9 cents to $2.52 per gallon, the Gulf Coast price rose over 8 cents to $2.30 per gallon, the Midwest price rose nearly 8 cents to $2.48 per gallon, the Rocky Mountain price rose nearly 7 cents to $2.32 per gallon, and the West Coast price rose nearly 5 cents to $3.03 per gallon.

The U.S. average diesel fuel price fell nearly 1 cent to $3.07 per gallon on March 18, nearly 10 cents higher than a year ago. The Midwest price fell nearly 2 cents to $2.99 per gallon, the Gulf Coast price fell over 1 cent to $2.87 per gallon, and the West Coast price fell nearly 1 cent to $3.50 per gallon. The Rocky Mountain price increased nearly 1 cent, remaining at $2.94 per gallon, and the East Coast price rose less than 1 cent, remaining at $3.12 per gallon.

Propane/propylene inventories rise

U.S. propane/propylene stocks increased by 1.0 million barrels last week to 51.1 million barrels as of March 15, 2019, 6.3 million barrels (14.0%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Gulf Coast, East Coast, and Rocky Mountain/West Coast inventories increased by 1.2 million barrels, 0.4 million barrels, and 0.1 million barrels, respectively, while Midwest inventories decreased by 0.7 million barrels. Propylene non-fuel-use inventories represented 12.1% of total propane/propylene inventories.

Residential heating fuel prices decrease

As of March 18, 2019, residential heating oil prices averaged nearly $3.22 per gallon, 1 cent per gallon below last week’s price but 16 cents per gallon above last year’s price at this time. Wholesale heating oil prices averaged $2.09 per gallon, nearly 4 cents per gallon less than last week’s price but 8 cents per gallon more than a year ago.

Residential propane prices averaged $2.41 per gallon, less than 1 cent per gallon lower than last week’s price and almost 8 cents per gallon lower than a year ago. Wholesale propane prices averaged nearly $0.84 per gallon, less than 1 cent per gallon above last week’s price but 3 cents per gallon below last year’s price.

March, 21 2019