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Last Updated: December 6, 2018
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Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b

  • After falling down to fresh lows last week – with WTI prices dipping below US$50/b at one point – crude oil prices improved after the G20 meeting in Buenos Aires, where the US and China agreed to a temporary truce over their trade war
  • While no concrete agreements over energy were announced at the G20 summit, the slightly thawing in trade tensions allowed crude benchmarks to rise slightly, assisted by an announcement by Canadian producers in Alberta that output would be cut by 325,000 b/d beginning January
  • Russia and Saudi Arabia agreed at the G20 summit to extend the OPEC+ deal into 2019, suggesting that a coordinated oil output cut was in the works, also supported prices ahead of OPEC’s meeting in Vienna this week
  • Not present at the OPEC meeting, however, will be Qatar, which quit the oil cartel in a surprise move; the tiny sultanate said it was quitting due to its small oil production, choosing instead to focus on its LNG industry, but the move can be seen as a response to the Saudi-led boycott of Qatar, calling into question Saudi Arabia’s ability to hold the fragile OPEC coalition together
  • Consensus among analysts point to OPEC+ agreeing to remove some 800,000 b/d of crude oil from the market beginning January, aimed at establishing a floor for oil prices at some US$65/b
  • The downward spiral of crude prices has put the brakes on US drilling activity, with 2 new oil rigs offset by the loss of 5 gas rigs last week; analysts are expecting shale explorers to cut spending budgets in 2019 in response to weak prices, raising spectres of the 2015 price slump
  • Crude price outlook: Ahead of the OPEC meeting on December 6, crude should be kept up by expectations of a renewed supply cut, with Brent likely to trade rangebound around US$61-63/b and WTI at US$52-53/b

Headlines of the week

Upstream

  • Buoyed by the prolific nature of the Permian Basin, Shell has announced plans to nearly double its production in the shale patch with AI-powered technology
  • China and the Philippines have set aside sovereignty issues, signing an agreement for joint exploration and development in the South China Sea
  • Facing severe pipeline bottlenecks, Canada’s Alberta province is looking to purchase rail cars to ship more crude oil by train out of the province towards the US, as a temporary measure while new pipeline are proposed and built
  • Shell has completed the sale of Shell E&P Ireland to Nephin Energy Holdings, which includes a 45% in the Corrib gas venture, for US$1.3 billion
  • In Norway, Shell also sold its interests in the Draugen and Gjøa fields for US$526 million to OKEA AS, but retains its interests in the Ormen Lange and Knarr fields, as well as the Troll, Valemon and Kvitebjørn projects
  • Petrobras has sold its stake in 34 onshore production fields to Brazilian firm 3R Petroleum for US$453.1 million, as well as stakes in three shallow-water offshore fields off Rio de Janeiro to Perenco for US$370 million
  • Pemex tripled its estimated reserves in the Ixachi field to 1.3 billion barrels of oil, calling it the ‘most important onshore field in 25 years’ and expecting peak production of 80,000 b/d of condensate and 720 mscf/d of gas by 2022

Downstream

  • Uganda has pushed back the opening of its first oil refinery to 2023, in line with estimates by Total, CNOOC and Tullow Oil, as crude oil production is now only expected to begin in 2021
  • Malaysia will be introducing a B10 biodiesel mandate in December over a phased rollout, with complete implementation expected by February 2018
  • Pertamina expects to begin works on upgrading its Balikpapan refinery in early 2019, aimed to increasing fuel standards to Euro V and upgrading capacity to process sour crude together with its current medium heavies
  • ExxonMobil plans to upgrade its Rotterdam refinery to expand Group II base stock production, following the installation of a new hydrocracker
  • The US EPA has increased its annual blending mandate for advanced biofuels by 15% and kept conventional biofuels blending requirement steady for 2019, while maintaining waivers for selected refineries

Natural Gas/LNG

  • Petronas and Vitol Asia have signed a long-term LNG supply agreement, with Petronas providing LNG from the LNG Canada project in Kitimat, providing up to 800,000 tons per annum for 15 years beginning 2024
  • Eni and Anadarko have been giving a 2023 deadline to submit key development plans for the Area 1 and 4 LNG complex in Mozambique
  • Tullow Oil is backing the attempt by three former Cove Energy executives in the Comoros Islands by taking stakes in Discover Exploration’s blocks, hoping to repeat the trio’s success in discovering the Rovuma block
  • South Korea’s Posco Daewoo has signed a deal with Brunei National Petroleum Company to jointly explore LNG opportunities in Brunei, with specific focus on the development of the Dehwa area operated by Posco Daewoo
  • Rosnedt and the Beijing Gas Group have set up a joint venture focusing on building and operating a network of up to 170 CNG fuel stations in Russia, using LNG as motor fuel

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Renewables became the second-most prevalent U.S. electricity source in 2020

In 2020, renewable energy sources (including wind, hydroelectric, solar, biomass, and geothermal energy) generated a record 834 billion kilowatthours (kWh) of electricity, or about 21% of all the electricity generated in the United States. Only natural gas (1,617 billion kWh) produced more electricity than renewables in the United States in 2020. Renewables surpassed both nuclear (790 billion kWh) and coal (774 billion kWh) for the first time on record. This outcome in 2020 was due mostly to significantly less coal use in U.S. electricity generation and steadily increased use of wind and solar.

In 2020, U.S. electricity generation from coal in all sectors declined 20% from 2019, while renewables, including small-scale solar, increased 9%. Wind, currently the most prevalent source of renewable electricity in the United States, grew 14% in 2020 from 2019. Utility-scale solar generation (from projects greater than 1 megawatt) increased 26%, and small-scale solar, such as grid-connected rooftop solar panels, increased 19%.

Coal-fired electricity generation in the United States peaked at 2,016 billion kWh in 2007 and much of that capacity has been replaced by or converted to natural gas-fired generation since then. Coal was the largest source of electricity in the United States until 2016, and 2020 was the first year that more electricity was generated by renewables and by nuclear power than by coal (according to our data series that dates back to 1949). Nuclear electric power declined 2% from 2019 to 2020 because several nuclear power plants retired and other nuclear plants experienced slightly more maintenance-related outages.

We expect coal-fired electricity generation to increase in the United States during 2021 as natural gas prices continue to rise and as coal becomes more economically competitive. Based on forecasts in our Short-Term Energy Outlook (STEO), we expect coal-fired electricity generation in all sectors in 2021 to increase 18% from 2020 levels before falling 2% in 2022. We expect U.S. renewable generation across all sectors to increase 7% in 2021 and 10% in 2022. As a result, we forecast coal will be the second-most prevalent electricity source in 2021, and renewables will be the second-most prevalent source in 2022. We expect nuclear electric power to decline 2% in 2021 and 3% in 2022 as operators retire several generators.

monthly U.S electricity generation from all sectors, selected sources

Source: U.S. Energy Information Administration, Monthly Energy Review and Short-Term Energy Outlook (STEO)
Note: This graph shows electricity net generation in all sectors (electric power, industrial, commercial, and residential) and includes both utility-scale and small-scale (customer-sited, less than 1 megawatt) solar.

July, 29 2021
PRODUCTION DATA ANALYSIS AND NODAL ANALYSIS

Kindly join this webinar on production data and nodal analysis on the 4yh of August 2021 via the link below

https://www.linkedin.com/events/productiondataanalysis-nodalana6810976295401467904/

July, 28 2021
Abu Dhabi Lifts The Tide For OPEC+

The tizzy that OPEC+ threw the world into in early July has been settled, with a confirmed pathway forward to restore production for the rest of 2021 and an extension of the deal further into 2022. The lone holdout from the early July meetings – the UAE – appears to have been satisfied with the concessions offered, paving the way for the crude oil producer group to begin increasing its crude oil production in monthly increments from August onwards. However, this deal comes at another difficult time; where the market had been fretting about a shortage of oil a month ago due to resurgent demand, a new blast of Covid-19 infections driven by the delta variant threatens to upend the equation once again. And so Brent crude futures settled below US$70/b for the first time since late May even as the argument at OPEC+ appeared to be settled.

How the argument settled? Well, on the surface, Riyadh and Moscow capitulated to Abu Dhabi’s demands that its baseline quota be adjusted in order to extend the deal. But since that demand would result in all other members asking for a similar adjustment, Saudi Arabia and Russia worked in a rise for all, and in the process, awarded themselves the largest increases.

The net result of this won’t be that apparent in the short- and mid-term. The original proposal at the early July meetings, backed by OPEC+’s technical committee was to raise crude production collectively by 400,000 b/d per month from August through December. The resulting 2 mmb/d increase in crude oil, it was predicted, would still lag behind expected gains in consumption, but would be sufficient to keep prices steady around the US$70/b range, especially when factoring in production increases from non-OPEC+ countries. The longer term view was that the supply deal needed to be extended from its initial expiration in April 2022, since global recovery was still ‘fragile’ and the bloc needed to exercise some control over supply to prevent ‘wild market fluctuations’. All members agreed to this, but the UAE had a caveat – that the extension must be accompanied by a review of its ‘unfair’ baseline quota.

The fix to this issue that was engineered by OPEC+’s twin giants Saudi Arabia and Russia was to raise quotas for all members from May 2022 through to the new expiration date for the supply deal in September 2022. So the UAE will see its baseline quota, the number by which its output compliance is calculated, rise by 330,000 b/d to 3.5 mmb/d. That’s a 10% increase, which will assuage Abu Dhabi’s itchiness to put the expensive crude output infrastructure it has invested billions in since 2016 to good use. But while the UAE’s hike was greater than some others, Saudi Arabia and Russia took the opportunity to award themselves (at least in terms of absolute numbers) by raising their own quotas by 500,000 b/d to 11.5 mmb/d each.

On the surface, that seems academic. Saudi Arabia has only pumped that much oil on a handful of occasions, while Russia’s true capacity is pegged at some 10.4 mmb/d. But the additional generous headroom offered by these larger numbers means that Riyadh and Moscow will have more leeway to react to market fluctuations in 2022, which at this point remains murky. Because while there is consensus that more crude oil will be needed in 2022, there is no consensus on what that number should be. The US EIA is predicting that OPEC+ should be pumping an additional 4 million barrels collectively from June 2021 levels in order to meet demand in the first half of 2022. However, OPEC itself is looking at a figure of some 3 mmb/d, forecasting a period of relative weakness that could possibly require a brief tightening of quotas if the new delta-driven Covid surge erupts into another series of crippling lockdowns. The IEA forecast is aligned with OPEC’s, with an even more cautious bent.

But at some point with the supply pathway from August to December set in stone, although OPEC+ has been careful to say that it may continue to make adjustments to this as the market develops, the issues of headline quota numbers fades away, while compliance rises to prominence. Because the success of the OPEC+ deal was not just based on its huge scale, but also the willingness of its 23 members to comply to their quotas. And that compliance, which has been the source of major frustrations in the past, has been surprisingly high throughout the pandemic. Even in May 2021, the average OPEC+ compliance was 85%. Only a handful of countries – Malaysia, Bahrain, Mexico and Equatorial Guinea – were estimated to have exceeded their quotas, and even then not by much. But compliance is easier to achieve in an environment where demand is weak. You can’t pump what you can’t sell after all. But as crude balances rapidly shift from glut to gluttony, the imperative to maintain compliance dissipates.

For now, OPEC+ has managed to placate the market with its ability to corral its members together to set some certainty for the immediate future of crude. Brent crude prices have now been restored above US$70/b, with WTI also climbing. The spat between Saudi Arabia and the UAE may have surprised and shocked market observers, but there is still unity in the club. However, that unity is set to be tested. By the end of 2021, the focus of the OPEC+ supply deal will have shifted from theoretical quotas to actual compliance. Abu Dhabi has managed to lift the tide for all OPEC+ members, offering them more room to manoeuvre in a recovering market, but discipline will not be uniform. And that’s when the fireworks will really begin.

End of Article 

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Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Worries about new Covid-19 infections worldwide dragging down demand just as OPEC+ announced that it would be raising production by 400,000 b/d a month from August onward triggered a slide in Brent and WTI crude prices below US$70/b
  • However, that slide was short lived as near-term demand indications showed the consumption remained relatively resilient, which lifted crude prices back to their previous range in the low US$70/b level, although the longer-term effects of the Covid-19 delta variants are still unknown at this moment
  • Clarity over supply and demand will continue to be lacking given the fragility of the situation, which suggests that crude prices will remain broadly rangebound for now

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July, 26 2021