Last week in the world oil:
- There are no clear trends in crude prices, with Brent and WTI stuck in
their respective ranges of US$57/b and US$52/b. Reductions in US
drilling rates were offset by Iraqi supply disruptions, while OPEC’s hints
that the supply freeze will persist did little to move the market.
- Mexico is planning a third auction in 2018, hiking up the pace as the
country seeks to exploit new-found private interest in its hydrocarbons in
a election year. The auction will focus on conventional onshore oil and gas
blocks, with terms to be announced early 2018 and awarded by mid-
2018. This joins the planned deepwater Gulf auction scheduled by
January 2018 and a shallow water auction in March 2018.
- BP and SOCAR will sign a new production-sharing agreement for a new
block, D-230, in the North Absheron basin of the Caspian Sea. With equal
stakes, this cements BP as the main international player in Azerbaijan,
with existing stakes in the Azer-Chirag- Guneshli and Shah Deniz fields.
- Thailand’s PTTEP is delaying the FID for the Mariana Oil Sands project in
Canada, the latest holdup in the region’s once booming oil sands sector.
There is a high likelihood that the project, 100% owned by PTTEP, may be
dropped, given the company’s recent focus on midstream and gas.
- The US active rig count dropped by 15 last week – 7 oil and 8 gas – as
drilling activity retreats against stagnant oil prices. All rig losses were
onshore, with the most declines in the Haynesville and Permian basins.
Downstream & Midstream
- Nigeria has announced that the planned 650 kb/d Dangote refinery, being
built by Africa’s richest man Aliko Dangote, will come onstream by end-
2019, which would help ease the country’s growing dependence on
imports. Envisioned as Nigeria’s own Jamnagar refinery, an operational
Dangote refinery will also ease the pressure on NNPC, which has been
struggling to find partners to help revamp its three existing refineries.
Natural Gas and LNG
- Natural gas action in the Eastern Mediterranean is heating up. With Egypt,
Israel, Greece and Cyprus already exploiting resources, Energean Oil &
Gas is backing a new player: Montenegro. Two blocks explored by the
Greek company hold an estimated 1.8 trillion cubic feet of recoverable gas
reserves, with Energean CEO Mathios Rigas saying that Montenegro is
sitting in the ‘sweet spot of untapped potential in the eastern Adriatic.’
Energean was awarded a 30-year licence for the blocks in March 2017.
- Russia’s Novatek is planning to expand the Yamal LNG by one more train.
With an additional capacity of 1 mtpa, the smaller fourth train is planned
for end-2019, with Yamal Trains 2 & 3 tracking ahead of schedule.
- BP’s Chariman Carl-Henric Svanberg has announced his retirement after
steering the supermajor through the Deepwater Horizon disaster just
months after he assumed his position. Svanberg will remain in his
position until a successor is identified.
Last week in Asian oil
- China will continue to be more and more dependent on imported crude,
as domestic production fell by 2.9% y-o- y to 3.78 mmb/d in September.
Low oil prices have made some marginal and ageing fields uneconomic,
exacerbating the country’s declining trend. Domestic natural gas output,
however, was up 10.7% y-o- y to 11.15 bcm, bringing YTD gas production
up by 9.1% y-o- y. With China’s private sector shying away from
developing the country’s ast shale oil and gas reserves after yeas of
limited success, the outlook is poor. Which makes recent deals like CEFC
China Energy’s US$9.1 billion investment in Rosneft more important, as it
gives China access to up to 260,000 bpd of Russian oil. China has also
apparently offered to purchase outright 5% of Saudi Aramco, potentially
circumventing the Saudi Arabian firm’s IPO ambitions.
- As Iraq’s strife with its rebel Kurdish province wanes following the
capture of Kirkuk, the country has wasted no time in making plans to
exploit the region’s large oil reserves. Iraqi Oil Minister announced plans
to collaborate with international investors to double oil production at the
northern Kirkuk fields to exceed one mmb/d. However, Iraq is unlikely to
work with Rosneft – as the Russia producer announced a deal with Iraqi
Kurdistan authorities to operate an oil export pipeline and purchase
stakes in five oil blocks for up to US$400 million. It may have lost Kirkuk,
but Iraqi Kurdistan still controls three northern provinces, and its only
outlet to export its crude is through a pipeline through Turkey, which is
under jeopardy from the recent independence referendum. The Rosneft
pipeline project, together with current Kurdish pipeline operator Kar
Group, would provide an alternative supply route… but continue to stoke
domestic tensions with the central Iraqi government.
- As Shell finalises its exit from the Iraqi upstream oil sector, Total is
gunning to fill the void left by the supermajor, which is focusing on
natural gas production in Basra. Total is reportedly aiming for the
Majnoon oilfield as well as the Nassiriya oil and gas project, both in the
south, signalling its interest to the Iraqi Oil Minister.
- Indonesia will be launching its second oil and gas licenceround for 2017
in November, despite the first auction’s deadline having been pushed
back twice. Acreage to be offered in the second round will comprise both
conventional and unconventional blocks. Delays are expected, given that
the government is still fine-tuning new upstream regulations that will
govern the gross split mechanism applicable to new E&P contracts – the
cause of the first 2017 round’s repeated postponements.
Natural Gas & LNG
- Indonesia has agreed to extend Inpex’s contract to operate the Masela
natural gas field by up to 27 years once the current contract expires in
2028. This comes after Inpex lobbied for the extension, given that
President Joko Widodo’s decision to reject a planned US$15 billion FLNG
facility in favour of an onshore facility had pushed anticipated start of
production by several years to the late 2020s. The extension – a standard
20-year extension and an additional seven years as compensation for
changing the LNG refinery development plan – was necessary assurance
for Inpex and its partner Shell to proceed with the project.
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Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.
Headline crude prices for the week beginning 13 May 2019 – Brent: US$70/b; WTI: US$61/b
Headlines of the week
Midstream & Downstream
The world’s largest oil & gas companies have generally reported a mixed set of results in Q1 2019. Industry turmoil over new US sanctions on Venezuela, production woes in Canada and the ebb-and-flow between OPEC+’s supply deal and rising American production have created a shaky environment at the start of the year, with more ongoing as the oil world grapples with the removal of waivers on Iranian crude and Iran’s retaliation.
The results were particularly disappointing for ExxonMobil and Chevron, the two US supermajors. Both firms cited weak downstream performance as a drag on their financial performance, with ExxonMobil posting its first loss in its refining business since 2009. Chevron, too, reported a 65% drop in the refining and chemicals profit. Weak refining margins, particularly on gasoline, were blamed for the underperformance, exacerbating a set of weaker upstream numbers impaired by lower crude pricing even though production climbed. ExxonMobil was hit particularly hard, as its net profit fell below Chevron’s for the first time in nine years. Both supermajors did highlight growing output in the American Permian Basin as a future highlight, with ExxonMobil saying it was on track to produce 1 million barrels per day in the Permian by 2024. The Permian is also the focus of Chevron, which agreed to a US$33 billion takeover of Anadarko Petroleum (and its Permian Basin assets), only for the deal to be derailed by a rival bid from Occidental Petroleum with the backing of billionaire investor guru Warren Buffet. Chevron has now decided to opt out of the deal – a development that would put paid to Chevron’s ambitions to match or exceed ExxonMobil in shale.
Performance was better across the pond. Much better, in fact, for Royal Dutch Shell, which provided a positive end to a variable earnings season. Net profit for the Anglo-Dutch firm may have been down 2% y-o-y to US$5.3 billion, but that was still well ahead of even the highest analyst estimates of US$4.52 billion. Weaker refining margins and lower crude prices were cited as a slight drag on performance, but Shell’s acquisition of BG Group is paying dividends as strong natural gas performance contributed to the strong profits. Unlike ExxonMobil and Chevron, Shell has only dipped its toes in the Permian, preferring to maintain a strong global portfolio mixed between oil, gas and shale assets.
For the other European supermajors, BP and Total largely matched earning estimates. BP’s net profits of US$2.36 billion hit the target of analyst estimates. The addition of BHP Group’s US shale oil assets contributed to increased performance, while BP’s downstream performance was surprisingly resilient as its in-house supply and trading arm showed a strong performance – a business division that ExxonMobil lacks. France’s Total also hit the mark of expectations, with US$2.8 billion in net profit as lower crude prices offset the group’s record oil and gas output. Total’s upstream performance has been particularly notable – with start-ups in Angola, Brazil, the UK and Norway – with growth expected at 9% for the year.
All in all, the volatile environment over the first quarter of 2019 has seen some shift among the supermajors. Shell has eclipsed ExxonMobil once again – in both revenue and earnings – while Chevron’s failed bid for Anadarko won’t vault it up the rankings. Almost ten years after the Deepwater Horizon oil spill, BP is now reclaiming its place after being overtaken by Total over the past few years. With Q219 looking to be quite volatile as well, brace yourselves for an interesting earnings season.
Supermajor Financials: Q1 2019