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Headline crude prices for the week beginning 30 December 2019 – Brent: US$68/b; WTI: US$61/b

  • Global oil prices finished the year on a relative high, with indications that the presumed upcoming supply glut might be less severe than expected, pushing Brent and WTI prices to 3-month highs.
  • Dragged up by the renewed OPEC+ supply deal and an imminent Phase 1 US-China trade deal, data released by US EIA showing that US crude inventories had fallen for a second consecutive level to its lowest point in two points (along with a fall in US crude exports) also supported prices
  • Rising supply from non-OPEC+ sources – including the US, Norway and Brazil – is still a concern, especially with a significant amount of crude from Guyana also entering the market; while OPEC+ is stressing adherence, calculations suggest that there may still be an immediate excess of 500,000 b/d of crude in 1H 2020
  • Members of the OPEC+ club have also signalled that they expect an end to the organisation’s attempts to prop of crude prices, with Russian Energy Minister Alexander Novak stating that the cuts ‘can’t last forever’, stressing a need to defend market share
  • After two weeks of gains, the US active rig count fell to the pre-New Year lull, dropping 8 oil rigs overall, while the number of gas rigs stayed flat for a total count of 805, or 278 fewer rigs y-o-y; major losses were seen in the Permian, where 9 rigs were lost
  • At the start of a new year, it looks like crude prices will hold their recent gains, but not much higher, as the market frets about impending oversupply; Brent and WTI should remain rangebound at US$65-67/b and US$60-62/b, respectively


Headlines of the week

Upstream

  • First oil from Guyana is now on the market, as ExxonMobil’s Liza field starts commercial production, ramping up to some 120,000 b/d over Q1 2020
  • Even more oil is coming from Guyana, as ExxonMobil and its partners Hess  and CNOOC struck oil again at the Mako-1 well, southeast of the Liza field, making it the 15th discovery in the Stabroek Block and increasing estimated recoverable resources in the block to some 6 billion barrels of oil equivalent
  • Hoping to follow in the footsteps of Guyana’s success, Apache and Total have formed a joint venture to explore Block 58 offshore Suriname, each holding a 50% working interest in the asset, which includes the Maka Central-1 well
  • South Africa has published its first draft of new oil and gas legislation that would give the state a 20% carried interest in all exploration and production rights, including a 10% participating interest for black partners and calling for the establishing of a national Petroleum Agency
  • Equinor and Rosneft have taken FID on the first stage of their North Komsomolskoye field development project, with the onshore field in Western Siberia estimated to hold some 250 million barrels of oil and 23 bcm of gas
  • After several years of dispute that halted production, Saudi Arabia and Kuwait have agreed to resume oil production in their shared neutral zone, which could return as much as 500,000 b/d of crude to the market
  • China’s CNOOC is to ramping up drilling in the South China Sea, with up to 30 wells planned in the Pearl River Mouth and Qiongdongnan basins over 2020

Midstream/Downstream

  • Nigeria’s NNPC will be increasing its stake in the Chevron-operated 33,000 b/d EGTL gas-to-liquids refinery near Lagos from 20% to 60%, which is part of a cost dispute resolution agreed between both parties

Natural Gas/LNG

  • Shell announced that it had made a ‘significant’ gas and condensate discovery in Western Australia’s Browse Basin, with the Bratwurst-1 well lying close enough to the Prelude FLNG facility to enable a future tie-back
  • Thailand’s PTTEP has sanctioned the start of its Lang Lebah gas project in Block Sk 410B in Sarawak, Malaysia, with production aimed to act as feedstock for the Petronas LNG export project in Bintulu
  • Delek Drilling has officially delayed the launch of production at the Leviathan gas field in Israel, following a court injunction halting operations and a delay in permits required from the Ministry of Environmental Protection
  • Eni has taken FID on the planned expansion of its LNG export facility in Nigeria, which would increase production capacity from a currently 22.5 million tpa to over 30 mtpa, involving a new liquefaction train and debottlenecking of the existing six trains
  • Private equity group KKR & Co and the Alberta Investment Management Corporation have taken a 65% stake in the 21 bcf/d Coastal GasLink Pipeline project in Canada, which will connect natural gas supply from Dawson Creek to the upcoming LNG export facility in Kitimat, British Columbia
  • The second liquefaction train at the Cameron LNG project in Louisiana has started up initial production, bringing total production capacity to 8 mtpa
  • Australia’s Woodside has signed a long-term 13-year LNG sales and purchase agreement with Germany’s Uniper Commodities, involving an initial 500,000 tpa of LNG in 2021 then rising to 1 million tpa from 2025 onwards

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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