Last week in world oil:
- With news that US drilling was rising at its fastest pace in two years and Asian buyers turning to avenues such as North Sea oil counteracting the (thus-far) effective OPEC supply cut, crude prices have not budged much from their positions around US$55/b for Brent and US$52/b for WTI.
Upstream & Midstream
- One of Donald Trump’s first executive orders as President of the USA has been a chaotic ban on citizens of seven Muslim countries entering the USA. This has prompted tit-for-tat measures by Iraq and Iran, moving to ban entry to Americans to their countries. For Iran, this could effectively freeze out American firms from participating in the revitalisation of Iran’s oil and gas industry, ceding ground to European and Chinese players. For Iraq, this complicates the matters as US army personnel as vital to Iraq’s fight against ISIS and poses a question mark on American participation (particularly ExxonMobil’s) in the Iraqi energy industry.
- The Keystone XL and Dakota Access oil pipelines are back in business, with President Donald Trump signalling support but demanding renegotiation to ‘secure a better deal for the US’. Some of the new caveats include the use of US-made products – difficult to achieve as the US steel industry isn’t up to par – and reducing environmental reviews.
- Shell is preparing a sale of its North Sea oil and gas assets to area specialist Chrysaor for US$3 billion, as it continues its divestment drive to pay for its acquisition of the BG Group. The package of assets will be a mix of older fields, new developments and infrastructure, which could inject new blood into an area in steady decline.
- Some 15 oil rigs started up last week, joined by 3 gas rigs, to raise the number of operational oil and gas rigs in the US to 712. This is the monthly fastest pace of additions in over three years, as US drillers capitalise on stronger oil prices as well as indications by the new Trump administration that they will support expansion in domestic upstream and reduce restrictions.
- Despite a USD415 million net income reported in Q4 2016, Chevron posted a USD497 million loss for 2016 as the slump in refining earnings outweighed recovering oil prices in H2 2016. The company replaced 95% of its production with new oil and gas reserves mostly from Kazakhstan, the US, and Australia
- The oilfield services company, Baker Hughes announced a USD417 million net loss on revenue of USD2.41 billion for Q4 2016. For the same quarter last year, the company lost more than USD1 billion on revenue of USD3.39 billion
- In 2012, Turkey referred Iran to the International Court of Arbitration for overpricing gas sales to Turkey between 2011 and 2015. The court ruled in favour of Turkey in February 2016, and as a result, Iran will pay Turkey USD1.9 billion in compensation and discount gas price by 13.5%.
- With BP’s annual forecast calling for energy demand to grow by a third through 2035, driven by demand in Asia and Africa, global players have turned their attention to African infrastructure. In Nigeria, General Electric has proposed a plan to revamp the country’s three ailing refineries, potentially creating a consortium with NNPC, which is in the process of being privatised. Italy’s Eni, as well, has announced plans to deepen Nigerian participation, both upstream and downstream.
- An explosion at the Tema refinery, the only processing site in Ghana, has caused the entire facility to be shut. The blast came upon the installation of a crude oil heating unit, destroying the new furnace; the plant will be restarted after reconfiguration but operating capacity will drop by a third.
- In more Shell divestment news, the supermajor is selling its 50% stake in petrochemical player Saudi Petrochemical (SADAF) to Saudi Basic Industries (SABIC) for US$820 million, the third Saudi Arabia-Shell ventures to be killed since 2014, after a natural gas ventures and US-based Motiva. Debt paring following the BG acquisition is the motive.
Last week in Asian oil:
Upstream & Midstream
- India has signed a deal with ADNOC to fill half of its new Mangalore crude oil storage facility. Up to 6 million barrels of UAE crude, mainly the Murban grade, will be stored at Mangalore, with the other half of storage already occupied by Iranian crude. It is a big step towards achieving India’s goal of increasing energy security through strategic reserves, but at only 10 days of oil demand, it is woefully behind other major oil consumers, with China aiming for 90 days and Japan having 160 days.
- The governments of Australia and Timor-Leste have given themselves a deadline of September 2017 to agree on a permanent maritime border between the two nations, settling once and for all the ownership of the Greater Sunrise field, with the results likely to benefit Timor-Leste.
Downstream & Shipping
- Despite Saudi Aramco’s decision to pull out of the massive RAPID refining and petrochemical hub in Johor, Malaysia’s Petronas has reaffirmed its plans. It remains on track internally for a 2019 start-up, though the departure of Saudi Aramco may force Petronas to secure another crude-rich partner to support the US$27 billion, 300 kb/d refinery. Iran is a possibility, with Petronas unlikely to go ahead alone due to its capex cuts.
Natural Gas & LNG
- Already facing cost spirals that have ballooned to over US$35 billion, Australia’s massive Ichthys LNG export project has been dealt another blow as engineering contractor CIMIC pulled out of the facility’s associated power plant. With the power plant – which would supply the site with electricity – touted at 89% completion, this suggest major disagreement within the consortium, which will only add to costs and delays, though Ichthys will still go ahead. It is not alone though; Chevron’s Gorgon and Shell’s floating Prelude projects are also facing major budget and timeline problems, delaying Australia’s gigantic LNG ramp up.
- Commercial operations have officially started at the Petronas LNG ninth liquefaction train in Bintulu, Sarawak. The site is a joint venture between Petronas and Japan’s JX Nippon Oil & Energy Corp, and the ninth train brings the total capacity of the Bintulu LNG plant to 30 million tons per year, much of which is destined to go north to Japan.
- PTTEP, the upstream arm of Thailand’s PTT Group has returned to the black, posting a net profit of US$372 million for 2016 after a loss of US$854 million in 2015, attributed to strong operational performances and cost control. Back on stronger financial footing, PTTEP plans to spend US$4 billion to investment, which will mainly focus on securing natural gas and LNG supplies to offset the decline in Thai gas production.
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Headline crude prices for the week beginning 18 March 2019 – Brent: US$67/b; WTI: US$58/b
Headlines of the week
Midstream & Downstream
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.
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
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