Easwaran Kanason

Co - founder of NrgEdge
Last Updated: September 1, 2020
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Business Trends
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It’s been a dry year so far for industry mergers and acquisitions – or A&D (acquisitions and divestitures) as the activity is known in the upstream world. But what little activity there is makes for some interesting reading. Particularly because it provides some idea for what the future could look like post-2020. Occidental Petroleum, for example, looks shaky as it furiously attempts to shed its debt load. Chevron, on the other hand, has had the last laugh, acquiring Noble Energy and finally managing to stitch together its disparate Permian assets into a more comprehensive tapestry. The latest of these intriguing moves also centres upon US shale, specifically the Permian golden goose. Malaysia’s national oil company Petronas is reportedly looking into buying its way into US shale, with driller DoublePoint Energy the target.

While neither firm has commented and reports suggest that talks are still at a preliminary stage, the possibilities are interesting. DoublePoint Energy has a 100,000 acre tranche of drilling rights smack in the prolific heart of the Permian, currently producing some 55,000 b/d of shale oil. Backed by private equity including the Blackstone Group, Apollo Global Management, Quantum Energy Partners and Magnetar Capital, DoublePoint is headed up by Cody Campbell and John Sellers – who made a name for themselves for patching together separate Permian drilling leases into a more cohesive whole, then selling that on to interested buyers for a tidy profit. Their previous largest sale (to Parsley Energy in 2017) amounted to US$2.8 billion.

Given the current climate, Campbell and Sellers might not be able to hit those same highs. After all, the industry is reticent to splash out wantonly in the Permian, given the history of steep production drops and the tricky oil price situation going forward. Chevron’s acquisition of Noble Energy, for example, was a relative steal at US$5 billion. DoublePoint Energy’s assets have already been previously assessed – a push by its private equity owners – with a 2019 valuation pegged at US$5 billion. It might fetch half of that today, making it a relatively safe bet for Petronas and still a decent sum for DoublePoint.

But what is more interesting is not this sale itself, but how it fits into the wider strategy of Petronas. Known as one of the most well-run of the national oil companies that emerged since the 1970s, Petronas leveraged its massive (at the time) asset base in Malaysia to go international. It moved into Central Asia, the Middle East and Africa early, opening out new upstream horizons there. It bet big on natural gas – specifically LNG – and remains one of the largest producers in the world and operates one of the largest LNG fleets through subsidiary MISC. It has recently expanded its downstream portfolio with the massive RAPID refinery in Johor, significantly expanding its footprint in high-value fuels and petrochemicals. And now, it seems, it has its sights set on a new frontier: the Americas.

Petronas and the Americas are no stranger to each other, but arguably the relationship kicked off in earnest when Petronas began exploring options to establish an LNG export facility in Canada’s British Columbia coast. That attempt hit several snags, its own Pacific Northwest project was derailed due to environmental sensitivity, with Petronas eventually buying a 25% stake in the Kitimat project led by Shell. But over the past two years, the pace has picked up. Petronas snapped up 10 blocks in Mexico, including some in the offshore Salinas Basin and Mexican Ridges. It bought a 50% stake in the Tartaruga Verde and Espadarte fields in Brazil’s offshore Campos Basin. It has an ongoing, and very promising drilling campaign in Suriname. It is aiming to have its first shale oil success through Argentina’s Vaca Muerta formation, through a US$2.3 billion joint venture with Argentine state oil firm YPF. And it is already in the USA, jointly announcing an ultra-deepwater discovery in the US Gulf of Mexico’s Monument well in January 2020 with its partners Equinor and Repsol.

Given this context, a Petronas presence in the Permian is not a possibility but an eventuality. If not DoublePoint Energy, then someone else. But the time seems ripe for the hunt, as the red hot-valuations of Permian players cool down to something more realistic and less risky since 2018. For the path that Petronas’ Americas expansion has taken – a stated focus for the company – this is a logical progression. And by the sounds of it, there might be more to come.

Market Outlook:

  • Crude price trading range: Brent – US$44-46/b, WTI – US$41-43/b
  • Crude oil prices firm up, as Hurricane Laura rips its way through the US Gulf, impacting offshore production and inland refineries across a key node in US energy
  • A further drop in the US crude stockpiles suggested that demand was quietly recovering, with the market also buoyed by signs that China had begun some intense crude buying in line with its trade commitments with the US signed back in January
  • In a landmark move, ExxonMobil was removed from the Dow Jones Industrial Average after 92 years, though Chevron (and now Honeywell) remains part of the 30-company strong stock market index that purports to measure America’s largest companies

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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