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Last Updated: October 6, 2017
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Last week in World oil:

Prices

  • With OPEC production rising in September as supplies from Nigeria and Libya recover, and US drilling numbers also show improvement, crude oil prices fell slightly from their recent highs – with Brent trading at about US$56/b and WTI at US$50/b.

Upstream

  • Chevron is committing some US$4 billion to ramp up crude production in the Permian Basin, aiming to grow its production there from 90,000 b/d in 2016 to over 400,000 b/d over the next five years. With a report calling the Permian a ‘super basin’ with some 60-70 billion barrels yet unpumped, Chevron expects production across all producers in the Permian to rise to 3.8 mmb/d in 2020, from a present 2.4 mmb/d.
  • Brazil’s latest round of oil block auctions revealed one very big winner – ExxonMobil – and one very big loser – the Santos basin. ExxonMobil bet big on the offshore pre-salt Campos basin, taking its first Brazilian blocks in five years. A total of eight blocks were handed to ExxonMobil, six in partnership with Petrobras, with changes in Brazilian regulations allowing private players to operate blocks on their own now. This could make ExxonMobil the pre-eminent pre-salt crude producer in Brazil. Meanwhile, of the 76 blocks offered in the prized offshore Santos basin, only one received a bid – by Australia’s Karoon Gas – a sign that in a persistent low oil price environment, upstream companies are still wary.
  • American drillers added oil rigs for the first time in seven weeks, as six new sites (mostly in Utah) brought the total oil rig count to 750 and the total rig count to 940.

Downstream & Midstream

  • Pemex’s largest Mexican refinery– the 330 kb/d Salina Cruz site – will remain offline until the third week of October, as a series of natural disasters including flooding, storms and two earthquakes devastated its refining production, causing product shortages across Mexico.

Natural Gas and LNG

  • The Ruby well in the Dutch North Sea cold hold more gas than previously anticipated, which would be a shot in the arm for waning gas production in the Netherlands. Flows from the well 20km offshore have been encouraging; with estimates suggesting it could contain some 2 trillion cubic feet of gas, more than the country’s current annual production. The partners on the Ruby well as Oranje-Nassau Energie, Energie Beheer Nederland, Hansa Hydrocarbons and Avista Capital Partners.
  • Trader Glencore has agreed to purchase Angola LNG in a multi-year deal that represents a new foray for the country. Angolan LNG has mainly been sold on the spot market – as the shale boom curtailed Angola’s initial plan of shipping LNG to the US – but the Glencore deal joins similar longer-term contracts signed by Angola with Vitol and Germany’s RWE, as jitters about Angola LNG’s reliability as a supplier fade. Russia major Gazprom has also signed a recent long-term deal, with Ghana National Petroleum Corp, to purchase LNG over a 12 year period beginning 2019. Details on volumes, however, were not released.

Last week in Asian oil

Downstream & Midstream

  • Petronas Chemicals has agreed to sell a 50% stake in its PRPC Polymers subsidiary to Saudi Aramco for some US$900 million. The sale will be completed by 15 March, 2018, when the new shareholding structure for the previously wholly-owned company takes effect. Devoted to developing, constructing and operating polymers and glycol plants in Malaysia, but having yet started operations, the tie-up with Saudi Aramco bring in a deep-pocketed partner for Petronas, while being part of Aamco’s diversification plan. Aramco and Petronas are already partners in the massive US$27 billion RAPID project in the southern state of Johor.

Natural Gas & LNG

  • Australia has let Shell, ConocoPhillips, Origin and Santos off the hook for the current gas shortage in the eastern states for now. The government had threatened to impose export curbs on the four producers if they did not redirect supplies meant for LNG export to the domestic market. There are three LNG export plants currently on Australia’s east coast, and the deal with the government will see the plants act on their promise to provide supplies to meet the government’s projected shortfall of up to 17% of domestic demand in 2018.
  • Woodside is partnering with Chevron to pick up three new exploration blocks off the north-west coast of Australia. With equal stakes in the permits, both companies are eyeing gas from the WA-528-P, WA-529-P and WA-530-P permits in the Carnarvon Basin to supply their respective – and competing – LNG plants in Western Australia. Operated by Chevron, the gas blocks are ideally placed some 250km north-west of the existing Pluto, Gorgon and Wheatstone plants, increasingly important as an LNG supply point to East Asia.
  • Thailand has decided to delay its auctions for the Erawan and Bongkot gas concessions for at least another month, expecting to only announce the winners in the middle of 2018. Chevron currently operates Erawan and state firm PTTEP operates Bongkot, with licenses set to expire in 2022 and 2023. Combined, both fields account for some 76% of Gulf of Thailand output, with the delay stemming from a government review of the new PSC terms to be used for the new licences. Chevron and PTTEP are bidding to keep the fields, while local firms Bangchak and Palang Sophon, along with Abu Dhabi’s Mubadala Petroleum and Japan’snMitsui Oil Exploration, are also in the running.
  • South Korea’s KOGAS is planning to build the country’s fifth LNG import terminal, targeting operational usage by 2025. The plant – which is planned to have ten 200,000 cbm storage tanks and associated infrastructure at the port of Dangjin near Incheon - will join the existing terminals at Incheon, Pyengtaek, Tongyeong and Samcheok.
  • India’s Reliance has outbid its rivals in a competitive auction for coal-bed methane produced from its own blocks in central India until at least March 2021. Reliance will purchase up to 3 million cbm/d of coal seam gas from its blocks in Sohagpur East and Sohagpur West in Madhya Pradesh, to be used as petrochemical feedstock.

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Suriname’s Mega Discovery

It was just over five years ago that ExxonMobil discovered first oil in Guyana, transforming the sleepy South American country into the world’s upstream hotspot in just half a decade. The strike rate there has been amazing – 18 discoveries out of 20 well campaigns, and more seem to coming as new discovery efforts get underway. This made Guyana the envy of its neighbours. And why not? The Guyanese economy is projected to grow at 86% y-o-y in 2020, despite the Covid-19 pandemic, as first commercial oil from the Liza field hit the market.

Just over the Guyana border, Suriname, a former Dutch colony had all the more reason to be envious. Unlike Guyana, Suriname has an established upstream industry. Managed by the state oil firm Staastsolie, the volumes are paltry: the onshore Calcutta and Tamabredjo field collectively produce at a current rate of 17,000 b/d. Guyana’s Liza field alone is 15 times larger than Suriname’s total crude output. But the Guyanese miracle always did herald some hope that some of that golden dust could blow Suriname’s way, not least because the giant offshore discoveries in the Staebroek block were just across the maritime border.

In January 2020, this bet proved right. US independent Apache announced it had made a ‘significant oil discovery’ at the Maka-Central 1 well, the first suggestion that the Cretaceous oil formation in Guyana extended southeast to Suriname. Two more discoveries were announced by Apache in quick succession, Sapakara West and, just this week, Kwaskwasi. All three are located in the 1.4 million acre offshore Block 58, which was originally held entirely by Apache before French supermajor Total bought into a 50% stake just before the Maka Central discovery was announced. Three discoveries in six month is quite a payoff, especially with the Kwaskwasi-1 well delivering the highest net pay and confirming a ‘world-class hydrocarbon resource’. More importantly, initial findings suggest that Kwaskwasi holds oil with API gravities in the 34-43 degree range, the sort of light oil that is perfect for petrochemicals and higher-grade fuels.

With Total scheduled to take over operatorship of the block after a fourth drilling campaign, the partners are eager to extend their streak. The Sam Croft drillship is scheduled to head to Keskesi, the fourth scheduled prospect in Block 58, after operations at Kwaskwasi-1 have concluded, and an additional exploration campaign is already in the plans for 2021.

Total and Apache aren’t the only ones playing in Surinamese waters, though they are the first to hit the payday. Most of the country’s offshore blocks have been apportioned, snapped up by ExxonMobil, Kosmos, Petronas, Tullow and Equinor, and all are hoping to be the next to announce a find. ExxonMobil, with Equinor and Hess Energy, have a good position in Block 59, just next to the Caieteur block in Guyana, while Kosmos is hunting in Block 42, right next to the Canje block in Guyana. However, it is Malaysia’s Petronas that is the next likely candidate. Present in Suriname since 2016, when it drilled the exploratory Roselle-1 well in Block 52, Petronas also has interests in Block 48 and Block 53, and recently completed a farm-out sale with ExxonMobil for 50% of Block 52. Its drilling campaign for the Sloanea-1 well is scheduled to begin in Q4 2020, and will be keenly watched by all in Suriname.

Unlike Guyana that had no state oil company, Suriname has existing national oil infrastructure. Staatsolie currently controls onshore and shallow water areas in the country. However, all wells drill in offshore Block A, B, C and D have turned out dry so far. That leaves Staatsolie in a situation: its own areas are not prolific as discoveries by Total, Apache, Petronas et al. For now, Staatsolie is looking to gain rights to 10-20% of any oil discovery within Suriname, but the framework for this is weak and it must navigate carefully to not antagonise the oil majors that are powering the discoveries in its waters. It will do well to avoid the confrontational attitude that is jeopardising LNG development in Papua New Guinea with ExxonMobil and Total, but Staatsolie does have a claim to Suriname’s oil riches for itself.

For now, it is exhilarating to observe the progress in this previously quiet corner of South America. It is the closest thing to frontier oil exploration in the 21st century, with each new discovery generating more and more excitement. Who would have thought there was so much oil left undiscovered? Guyana has shot into the spotlight, Suriname is starting its own ascent and… who knows… could French Guiana be next?

End of Article 

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August, 01 2020
2019 U.S. coal production falls to its lowest level since 1978

U.S. total annual coal production

Source: U.S. Energy Information Administration, Annual Coal Report

In 2019, U.S. coal production totaled 706 million short tons (MMst), a 7% decrease from the 756 MMst mined in 2018. Last year’s production was the lowest amount of coal produced in the United States since 1978, when a coal miners’ strike halted most of the country’s coal production from December 1977 to March 1978. Weekly coal production estimates from the U.S. Energy Information Administration (EIA) show the United States is on pace for an even larger decline in 2020, falling to production levels comparable with those in the 1960s.

2019 annual coal production by state

2019 annual coal production, top 10 coal-producing states


Source: U.S. Energy Information Administration, Annual Coal Report

Wyoming produces more coal than any other state, representing 39% of U.S. coal production in 2019, at 277 MMst, which is 9% lower than its coal production in 2018. Coal production in West Virginia, the state with the second-highest coal output, fell by a relatively smaller 2% in 2019. West Virginia is a primary producer of metallurgical coal, which saw sustained demand for exports in 2019. Coal production recently stopped in two states, Kansas in 2017 and Arkansas in 2018. Arizona stopped producing coal in the fall of 2019 when the coal-fired Navajo Generating Station and adjacent Kayenta coal mine that supplied it both closed.

EIA estimates weekly coal production using coal railcar loadings. In 2020, weekly coal railcar loadings have been trending much lower than 2019 levels, and most recent year-to-date coal railcar loadings were down 27% compared with 2019.

U.S. weekly railcar loadings

Source: U.S. Energy Information Administration, Weekly Coal Production

The decline of U.S. coal production so far in 2020 reflects less demand for coal internationally and less generation from U.S. coal-fired power plants. U.S. coal exports through May 2020 are 29% lower than during the first five months of 2019. U.S. coal-fired generation fell to a 42-year low in 2019, decreasing nearly 16% from the previous year, and has fallen another 34% through May 2020.

Estimated U.S. coal production through mid-July 2020 is 27% lower than the average annual 2019 output, and EIA expects these reductions in production to persist during the remainder of the year. In the latest Short-Term Energy Outlook (STEO), EIA forecasts a 29% decline in U.S. coal production in 2020.

EIA forecasts that U.S. coal production will increase by 7% in 2021, when rising natural gas prices may cause some coal-fired electric power plants to become more economical to dispatch. Much of EIA’s projected recovery in coal production is in the western United States.

Principal contributor: Rosalyn Berry

July, 29 2020
Key Upstream Positive Developments Since April 2020

Amid the unprecedented upheaval that has taken its toll on the world and, in particular the energy industry in the first half of this year, life goes on. Despite shut-ins, weak prices, huge impairments, gloomy forecasts and business challenges, life still goes on. Rigs are still running, exploration is still being conducted and projects are still being approved. The oil and gas world has weathered a huge storm, but that has not stopped it from focusing on necessary work that is vital for the future of the industry itself and the global economy. We have summarised a list of key upstream announcements and developments since April.

One of the major headlines that came out over the past three months was news that Total’s giant LNG in Mozambique has secured as much as US$16 billion in funds from various financial institutions. This is the single largest foreign direct investment project in Africa ever, matching the total current GDP of Mozambique. The speed at which Total completed financing for the US$23 billion project (which taps in the gigantic Golfinho and Atum natural gas fields) is quite remarkable, when the ExxonMobil-led Rovuma LNG next door is facing delays. In fact, the funding raised US$600 million than expected, representing the faith that the 13.1 million ton per annum project, potentially expandable to 43 mtpa, will pay off in the long run. For Total, this will be a hedge, given that its LNG efforts in Papua New Guinea are currently still stymied by a showdown against the country’s new government.

Chevron also had some major news to publish. After failing to acquire Anadarko in 2019 in a dramatic storyline against Occidental Petroleum, the US supermajor has swooped in to acquire US independent Noble Energy for some US$5 billion. The acquisition neatly replaces what the original Anadarko purchase was supposed to achieve – expand Chevron’s presence in the prolific US onshore shale basins, with Noble’s 92,000 acres in the Permian noted as being ‘largely contiguous and adjacent’ to Chevron’s current assets. Noble will also bring with it established positions in the Eagle Ford basin, significant US midstream assets and upstream assets in Israel and Equatorial Guinea, swelling Chevron’s proven oil and gas reserves by 18%. For that amount of potential, the price is a steal. With smaller shale players under pressure, expect more acquisitions of this sort to be announced by deep-pocketed bargain hunters.

Chevron wasn’t the only one to make acquisitions. ConocoPhillips splashed out US$375 million to take up land in Western Canada’s liquids-rich Montney formation, taking the Inga-Fireweed asset from Kelt Exploration. Trident Energy completed its purchase of 10 concessions in the offshore Pampo and Enchova clusters in Brazil from Petrobras. And trader Vitol announced a rara avis, a new US upstream venture called Vencer Energy, focusing on acquiring and operating mature assets in the US Lower 48 region from its base in Houston.

New discoveries have also been coming at a regular speed. Despite divesting assets, Petrobras announced two new discoveries in the offshore Buzios and Albacora pre-salt fields, with reserves of ‘excellent quality’. Eni continues its winning run in Egypt with the new Bashrush natural gas discovery in the Mediterranean Sea, while MOL made its lucky 13th discovery in Pakistan with the Mamikhel South-1 well (the tenth in the TAL Block alone) that revealed ‘significant gas and condensate reserves’. ExxonMobil has restarted two of its four drillships in Guyana and Petronas has handed out contracts in Suriname, so more discoveries are due from that part of the Caribbean. Neptune Energy hit oil at the Dugong well in the Norwegian North Sea, and China’s CNOOC announced a ‘significant discovery’ at the Huizhou 26-6 well in the Pearl River Mouth Basin – the first mid-to-large sized oil and gas field in the area.

CNOOC will be hoping the Huizhou discovery will continue its streak of recent discoveries, boosting domestic Chinese upstream output. Its Luda 21-2/16-3 asset, in the Bohai Sea’s Liaodong Bay, has just started up production, reaching a peak of 25,600 b/d in 2022. Sinopec is also marshalling resources, announcing a US$770 million plan to develop the Dingbei gas prospect in Ningxia and its 230 bcm of natural gas.

Medco reported first gas from the Meliwis field off East Java in Indonesia from an unmanned platform, while the National Iranian Oil Co shrugged off a domestic economic crisis to partner with Persia Oil and Gas Industry Development Co for US$463 million to re-develop the Yaran field in the Khuzestan Province, raising output by 40 million barrels over 10 years. And then in frozen Siberia, where Novatek is speeding ahead with LNG, Gazprom Neft and Shell have agreed to collaborate on developing the Leskinsky and Pukhutsyayakhshy blocks in the Gydan Peninsula: an unusual display of cooperation between a Russian state firm and a Western supermajor.

This is not an exhaustive list of recent developments in the upstream oil and gas corner of the universe. They are the most notable, but there are other signs that the thaw is coming and the industry can recover and begin to grow again. Covid-19 may be something that we must all learn to live with going forward, but life will always go on, and this too shall pass.

Market Outlook:

  • Crude price trading range: Brent – US$42-44/b, WTI – US$40-42/b
  • Global crude oil price markers remain stuck in the lower US$40/b area, as concerns of demand linger given the accelerating rate of Covid-19 in the Americas
  • News that OPEC+ was looking for a gradual phasing into the new supply quota level provides some support on the supply side, while key developments in potential Covid-19 vaccines indicate that first availability could be as early as September
  • A massive stimulus package agreed by the EU and positive messaging of recovery in Asia after two quarters of bad economic data also offer hope that growth could resume soon, though global trends are likely to be uneven given the situation in the Americas

End of Article

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End of Article

In this time of COVID-19, we have had to relook at the way we approach workplace learning. We understand that businesses can’t afford to push the pause button on capability building, as employee safety comes in first and mistakes can be very costly. That’s why we have put together a series of Virtual Instructor Led Training or VILT to ensure that there is no disruption to your workplace learning and progression.

Find courses available for Virtual Instructor Led Training through latest video conferencing technology.


July, 26 2020