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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Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.
Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.
When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.
This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017–18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017–18—including a bomb cyclone—resulted in record withdrawals from storage, increasing the deficit to the five-year average.
In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average.
The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report
The level of working natural gas inventories relative to the previous five-year average tends to be inversely correlated with natural gas prices. Front-month futures prices at the Henry Hub, the main price benchmark for natural gas in the United States, were as low as $1.67 per million British thermal units (MMBtu) in early 2016. At about that same time, natural gas inventories were 874 Bcf more than the previous five-year average.
By the winter of 2018–19, natural gas front-month futures prices reached their highest level in several years. Natural gas inventories fell to 725 Bcf less than the previous five-year average on November 30, 2018. In recent weeks, increasing the Lower 48 states’ natural gas storage levels have contributed to lower natural gas futures prices.
Source: U.S. Energy Information Administration, Weekly Natural Gas Storage Report and front-month futures prices from New York Mercantile Exchange (NYMEX)
Headline crude prices for the week beginning 14 October 2019 – Brent: US$59/b; WTI: US$53/b
Headlines of the week
Amid ongoing political unrest, Ecuador has chosen to withdraw from OPEC in January 2020. Citing a need to boost oil revenues by being ‘honest about its ability to endure further cuts’, Ecuador is prioritising crude production and welcoming new oil investment (free from production constraints) as President Lenin Moreno pursues more market-friendly economic policies. But his decisions have caused unrest; the removal of fuel subsidies – which effectively double domestic fuel prices – have triggered an ongoing widespread protests after 40 years of low prices. To balance its fiscal books, Ecuador’s priorities have changed.
The departure is symbolic. Ecuador’s production amounts to some 540,000 b/d of crude oil. It has historically exceeded its allocated quota within the wider OPEC supply deal, but given its smaller volumes, does not have a major impact on OPEC’s total output. The divorce is also not acrimonious, with Ecuador promising to continue supporting OPEC’s efforts to stabilise the oil market where it can.
This isn’t the first time, or the last time, that a country will quit OPEC. Ecuador itself has already done so once, withdrawing in December 1992. Back then, Quito cited fiscal problems, balking at the high membership fee – US$2 million per year – and that it needed to prioritise increasing production over output discipline. Ecuador rejoined in October 2007. Similar circumstances over supply constraints also prompted Gabon to withdraw in January 1995, returning only in July 2016. The likelihood of Ecuador returning is high, given this history, but there are also two OPEC members that have departed seemingly permanently.
The first is Indonesia, which exited OPEC in 2008 after 46 years of membership. Chronic mismanagement of its upstream resources had led Indonesia to become a net importer of crude oil since the early 2000s and therefore unable to meet its production quota. Indonesia did rejoin OPEC briefly in January 2016 after managing to (slightly) improve its crude balance, but was forced to withdraw once again in December 2016 when OPEC began requesting more comprehensive production cuts to stabilise prices. But while Indonesia may return, Qatar is likely gone permanently. Officially, Qatar exited OPEC in January 2019 after 48 years of continuous membership to focus on natural gas production, which dwarfs its crude output. Unofficially, geopolitical tensions between Qatar and Saudi Arabia – which has resulted in an ongoing blockade and boycott – contributed to the split.
The exit of Ecuador will not make much material difference to OPEC’s current goal of controlling supply to stabilise prices. With Saudi production back at full capacity – and showing the willingness to turn its taps on or off to control the market – gains in Ecuador’s crude production can be offset elsewhere. What matters is optics. The exit leaves the impression that OPEC’s power is weakening, limiting its ability to influence the market by controlling supply. There are also ongoing tensions brewing within OPEC, specifically between Iran and Saudi Arabia. The continued implosion of the Venezuelan economy is also an issue. OPEC will survive the exit of Ecuador; but if Iran or Venezuela choose to go, then it will face a full-blown existential crisis.
Current OPEC membership: