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Last Updated: April 8, 2020
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Forecast Highlights

Global liquid fuels

  • Although all market outlooks are subject to many risks, the April edition of EIA’s Short-Term Energy Outlook is subject to heightened levels of uncertainty because the impacts of the 2019 novel coronavirus disease (COVID-19) on energy markets are still evolving. The COVID-19 pandemic has caused significant changes in energy fuel supply and demand patterns. Crude oil prices, in particular, have fallen significantly since the beginning of 2020, largely driven by the economic contraction caused by COVID-19 and a sudden increase in crude oil supply following the suspension of previously agreed upon production cuts among the Organization of the Petroleum Exporting Countries (OPEC) and partner countries. Similar uncertainties persist across EIA’s outlook for other energy sources, including natural gas and electricity. Despite recent news of OPEC+ emergency meetings within the next few days to discuss production levels, without an agreement actually in place, EIA assumes no re-implementation of an OPEC+ agreement during the forecast period. If there is ultimately an agreement, this forecast will incorporate that information into its ensuing release.
  • EIA forecasts that the United States will return to being a net importer of crude oil and petroleum products in the third quarter of 2020 and remain a net importer in most months through the end of the forecast period. This is a result of higher net imports of crude oil and lower net exports of petroleum products. Net crude oil imports are expected to increase because as U.S. crude oil production declines, there will be fewer barrels available for export. On the petroleum product side, net exports will be lowest in the third quarter of 2020, when U.S. refinery runs are expected to decline significantly.
  • Brent crude oil prices averaged $32/barrel (b) in March, a decrease of $24/b from the average in February and the lowest monthly average since January 2016. EIA forecasts Brent crude oil prices will average $33/b in 2020, $10/b lower than in last month’s STEO and down from an average of $64/b in 2019. EIA expects prices will average $23/b during the second quarter of 2020 before increasing to $30/b during the second half of the year. EIA forecasts that average Brent prices will rise to an average of $46/b in 2021, $10/b lower than forecast last month, as a return to declining global oil inventories puts upward pressure on prices.
  • EIA estimates global petroleum and liquid fuels consumption averaged 94.4 million barrels per day (b/d) in the first quarter of 2020, a decline of 5.6 million b/d from the same period in 2019. EIA expects global petroleum and liquid fuels demand will decrease by 5.2 million b/d in 2020 from an average of 100.7 million b/d last year before increasing by 6.4 million b/d in 2021. Lower global oil demand growth for 2020 in the April STEO reflects growing evidence of significant disruptions to global economic activity along with reduced expected travel globally because of COVID-19.
  • EIA expects that global liquid fuels inventories will grow by an average of 3.9 million b/d in 2020 after falling by about 0.2 million b/d in 2019. EIA expects inventory builds will be largest in the first half of 2020, rising at a rate of 5.7 million b/d in the first quarter and increasing to builds of 11.4 million b/d in the second quarter as a result of widespread travel limitations and sharp reductions in economic activity. Firmer demand growth as the global economy begins to recover and slower supply growth will contribute to global oil inventory draws beginning in the fourth quarter of 2020. EIA expects global liquid fuels inventories will decline by 1.7 million b/d in 2021.
  • EIA forecasts significant decreases in U.S. liquid fuels demand during the first half of 2020 as a result of COVID-19 travel restrictions and significant disruptions to business and economic activity. EIA expects that the largest impacts will occur in the second quarter of 2020, before gradually dissipating over the course of the next 18 months. EIA expects U.S. motor gasoline consumption to fall by 1.7 million b/d from the first quarter of 2020 to an average of 7.1 million b/d in the second quarter, before gradually increasing to 8.9 million b/d in the second half of the year. U.S. jet fuel consumption will fall by 0.4 million b/d from the first quarter of 2020 to average 1.2 million b/d in the second quarter. U.S. distillate fuel oil consumption would see a smaller decline, falling by 0.2 million b/d to average 3.8 million b/d over the same period. In 2020, EIA forecasts that U.S. motor gasoline consumption will average 8.4 million b/d, a decrease of 9% compared with 2019, while jet fuel and distillate fuel oil consumption will fall by 10% and 5%, respectively over the same period.
  • For the April–September 2020 summer driving season, EIA forecasts U.S. regular gasoline retail prices will average $1.58 per gallon (gal), down from an average of $2.72/gal last summer (Summer Fuels Outlook). The lower forecast gasoline prices reflect lower forecast crude oil prices and significantly lower gasoline demand in the second quarter of 2020 driven by COVID-19 travel restrictions and disruptions to domestic economic activity. For all of 2020, EIA expects U.S. regular gasoline retail prices to average $1.86/gal and gasoline retail prices for all grades to average $1.97/gal.
  • EIA has revised its current forecast of domestic crude oil production down from the March STEO, as a result of lower crude oil prices. EIA forecasts U.S. crude oil production will average 11.8 million b/d in 2020, down 0.5 million b/d from 2019. In 2021, EIA expects U.S. crude production to decline further by 0.7 million b/d. If realized, the 2020 production decline would mark the first annual decline since 2016. Typically, price changes impact production after about a six-month lag. However, current market conditions, combined with the COVID-19 pandemic, will likely reduce this lag as many producers have already announced plans to reduce capital spending and drilling levels.

Natural gas

  • In March, the Henry Hub natural gas spot price averaged $1.74 per million British thermal units (MMBtu). Warmer-than-normal temperatures in March reduced demand for space heating and put downward pressure on prices. EIA forecasts that prices will begin to rise at the end of the second quarter of 2020 as U.S. natural gas production declines and natural gas use for power generation increases the demand for natural gas. EIA forecasts that Henry Hub natural gas spot prices will average $2.11/MMBtu in 2020 and then increase in 2021, reaching an annual average of $2.98/MMBtu because of lower natural gas production compared to 2020.
  • EIA expects residential consumption of natural gas to average 12.9 billion cubic feet per day (Bcf/d) in 2020, down 5.8% from the 2019 average primarily because of warmer-than-normal weather in the first quarter. Similarly, EIA expects commercial consumption of natural gas to average 9.0 Bcf/d in 2020, a decrease of 7.1%, as a result of warm weather and the slowing economy. EIA forecasts industrial natural gas consumption to average 22.9 Bcf/d in 2020, about the same as in 2019. The industrial forecast is down from the previously expected 6.5% growth in the March STEO, as less manufacturing activity in 2020 weakens the growth potential for industrial natural gas consumption.
  • U.S. dry natural gas production set a record in 2019, averaging 92.2 Bcf/d. EIA forecasts dry natural gas production will average 91.7 Bcf/d in 2020, with monthly production falling from an estimated 94.4 Bcf/d in March to 87.5 Bcf/d in December. Natural gas production declines the most in the Appalachian and Permian regions. In the Appalachian region, low natural gas prices are discouraging producers from engaging in natural gas-directed drilling, and in the Permian region, low oil prices reduce associated gas output from oil-directed wells. In 2021, forecast dry natural gas production averages 87.5 Bcf/d, rising in the second half of 2021 in response to higher prices.
  • EIA estimates that total U.S. working natural gas in storage ended March at 2.0 trillion cubic feet (Tcf), 17% more than the five-year (2015–19) average. In the forecast, inventories rise by 1.9 Tcf during the April through October injection season to reach almost 3.9 Tcf on October 31.
  • EIA forecasts that U.S. liquefied natural gas exports will average 6.6 billion cubic feet per day (Bcf/d) in the second quarter of 2020 and 6.0 Bcf/d in the third quarter of 2020. Liquefied natural gas exports in the third quarter 2020 are 0.3 bcf/d lower compared with the March STEO forecast because of lower expected global demand for natural gas.

Electricity, coal, renewables, and emissions

  • The economic slowdown and stay-at-home orders are likely to affect U.S. electricity consumption over the next few months. EIA expects the largest impact will occur in the commercial sector where forecast retail sales of electricity fall by 4.7% in 2020 due to the closure of many businesses. Similarly, EIA expects retail sales of electricity to the industrial sector will fall by 4.2% in 2020 as many factories cut back production. Forecast U.S. sales of electricity to the residential sector fall by 0.8% in 2020, as reduced power usage resulting from milder winter and summer weather is offset by increased household electricity consumption as much of the population stays at home.
  • EIA forecasts that total U.S. electric power sector generation will decline by 3% in 2020. Renewable energy sources account for the largest proportion of new generating capacity in 2020, driving EIA’s forecast that renewable generation by the electric power sector will grow by 11% this year. Renewable energy is typically dispatched whenever it is available because of its low operating cost. The forecast for lower overall electricity demand leads to an expected decline in fossil-fuel generation, especially at coal-fired power plants. EIA expects that coal generation will fall by 20% in 2020. Forecast natural gas generation rises by 1% this year, reflecting favorable fuel costs and the addition of new generating capacity.
  • Although EIA expects renewable energy to be the fastest growing source of electricity generation in 2020, the effects of COVID-19 and the resulting economic slowdown are likely to have an impact on new generating capacity builds over the next few months. EIA expects that the electric power sector will add 19.4 gigawatts of new wind capacity and 12.6 gigawatts of utility-scale solar capacity in 2020. These annual wind and solar capacity additions are 5% and 10% lower, respectively, than expected in the previous STEO.
  • EIA forecasts that U.S. coal production will total 537 million short tons (MMst) in 2020, down 153 MMst (22%) from 2019. Lower production reflects declining demand for coal in the electric power sector, lower demand for U.S. exports, and a number of coal mines that have been idled for extended periods as a result of COVID-19. EIA forecasts that total coal consumption will decrease by 19% in 2020, driven primarily by electric power sector demand, which will fall by 107 MMst (20%) in 2020. Total coal exports also decline, as European demand is affected by economic slowdown.
  • After decreasing by 2.7% in 2019, EIA forecasts that energy-related carbon dioxide (CO2) emissions will decrease by 7.5% in 2020 as the result of the slowing economy and restrictions on business and travel activity related to COVID-19. In 2021, EIA forecasts that energy-related CO2 emissions will increase by 3.6%. Energy-related CO2 emissions are sensitive to changes in weather, economic growth, energy prices, and fuel mix.

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What’s Next For Canadian Oil Sands

It cannot be said that the conversation around sustainability and carbon intensity in the energy industry happened overnight, since the topic has been a subject for over five decades. But what has changed is that there has been a major acceleration in the discussion in the last year, and even the last month. The European majors and supermajors have all adopted ambitious carbon-neutral goals – even though some jurisdictions are saying that those aren’t even enough. Over the pond, even shareholders are pushing the traditionally more reticent American giants to adopting stronger climate change goals. Nothing is more emblematic of this change that the shareholder revolt at ExxonMobil’s recent AGM, where upstart activist investor Engine No. 1 managed to oust a quarter of ExxonMobil’s board; the initial tally saw two of its candidates elected, but the final numbers showed that three of Engine No. 1’s nominees now sit on the Board of Directors with a remit to initiate climate change manoeuvres from the inside.

That sort of conversation will be jittery for a particular section of the industry: Canadian oil sands – the heavy, sandy deposits of bitumen in Alberta that provide Canada with the third-largest proven oil reserves in the world. Extracting this heavy stuff is expensive, requiring large-scale excavation and massive capital spending that only really made economic sense with the oil price boom in the late 2000s. Shipping this tarry substance is also a challenge, necessitating dilution with lighter crudes to be shipped via pipeline – which is the only major viable route to market for landlocked Alberta, sending the tarry substance all the way south to the US Gulf Coast for processing. The problem is that extracting oil sands is extremely energy-intensive – with the main culprit being steam injection to liquify the underground bitumen – that has resulted in some of the highest carbon emissions per barrel in the world. In a world racing towards net zero carbon emissions, that is quickly proving to be unacceptable.

So while the climate change debate rages on in the boardrooms of the largest energy firms, the exit has already begun from Alberta, operationally and financially. The latest moves come from Chevron, which saw its shareholders overturn the company’s recommendation to instil stricter emissions targets for its crude, and the New York State Common Retirement Fund, the third-largest in the USA. Chevron’s CEO Mike Wirth recently signaled that he was open to offloading its 20% stake in the Athabasca oil sands project, stating that even though it generates ‘pretty good cash flow without needing much capital’ it was not a ‘strategic position’. Wirth insisted that Chevron wasn’t operating on a ‘fire-sale mentality’ but would consider selling if it got ‘fair value’ – with in business-speak is basically as invitation for offers. But would those offers be forthcoming? Investors all around the world have pulled back from financing Canadian oil sands, limiting the pool of potential buyers. In April, the New York state pension fund restricted investment in six oil sands companies – Imperial Oil, Canadian Natural Resources, MEG Energy Corp, Athabasca Oil Corp, Japan Petroleum Exploration and Cenovus Energy – claiming that they ‘do not have viable plans to adapt to the low-carbon future, posing significant risks for investors’. The amount of funds (US$7 million) is a drop in the ocean for the US$248 billion pension fund, but the message it sends is loud and clear.

Taken as it is, this could be an exit. But taken as a collective movement considering divestments over the past 3 years, this is an exodus. In May 2020, Norges Bank Investment Management – the world’s largest sovereign wealth fund with over US$1 trillion in assets gleaned from Norway’s oil industry – pulled back entirely from Canadian oil sands, selling nearly US$1 billion in four major firms citing concerns over carbon emissions. While no other major pension fund has followed suit, private investors have, including titan BlackRock that has begun to exclude oil sands from its major funds Financing is also proving tricky, with a string of major banks – including HSBC, ING and BNP Paribas – either paring back or stopping lending entirely to the industry; the insurance industry is also pulling back, with The Hartford stopping investing or insuring of the Alberta crude oil industry.

These high-profile investment and financing moves have dimmed the shimmer of an industry that was never that clean to begin with. But what will hurt is the pullback of upstream players, which hollows out the pool of companies left to exploit what is an increasingly unattractive asset. Before Chevron even contemplate its sale, Shell already sold its assets in 2017 for US$8.5 billion and ConocoPhillips offloaded to Cenovus Energy as part of a broader sale including gas assets for US$13.3 billion, also in 2017. Norway’s Equinor, too, has liquidated its position. Then in February 2021, ExxonMobil dropped a bombshell – effectively eliminating every drop of oil sands crude from its worldwide reserves, a tacit admission that oil sands would not form part of its upstream focus (at least at current prices) for the foreseeable future, especially with more attractive propositions in Guyana and the Permian. Given its recent shareholder revolt, it is unlikely that oil sands will be back on the menu ever.

The players in Alberta are trying to fight back. Having been consolidated in less than a dozen major players – from oil sands specialists to more integrated players such as Suncor – the industry is trying to rally institutional support, stating that traditional industry is still necessary to build the clean energy industries of the future. Suncor’s CEO Mark Little puts it this way: ‘this is way more complicated (than its seems)… the wind farm can’t be the solution to every problem. It’s not. So we need to find innovative solutions.” The oil sands patch’s biggest players are also banding together to form an alliance to achieve net-zero greenhouse gas emissions by 2050 – similar to the goals of most energy majors – as it tries to convince not just the world, but also Canada’s own government that Alberta has a continued role in the country’s energy transition. Efforts include linking facilities in Ford McMurray and Cold Lake to a carbon sequestration hub, expanding carbon capture and storage technology, accelerating clean hydrogen and other clean technologies such as direct air capture and fuel switching. The timeframe and viability of this is critical, given that Prime Minister Justin Trudeau has already announced plans to raise Canada’s carbon price steeply to accelerate its energy transition.

Those are bold plans and bold ambitions. But will it be enough? Can the exodus be stemmed? Or will the industry be whittled down to a handful of local players isolated from the wider energy world, removed from climate change engagement completely? It is difficult to tell at this point, but at the very least, things are starting to move in the right direction. Even if the pace is as slow as the crude sludge mined in Alberta.

End of article 

Market Outlook:

-       Crude price trading range: Brent – US$71-73/b, WTI – US$69-71/b

-       Confidence in the crude markets has vaulted global price benchmarks to their highest level in two years, with both Brent and WTI exceeding the US$70/b psychological level

-       Underpinning this rally are signs that vaccinations are boosting economic activity, with the likelihood of some travel and hospitality sectors reopening fully across the northern hemisphere’s summer, while crude marker indication show tightness in the market

-       That will reinforce OPEC+’s position to ease its supply quotas from July onwards, with club’s goal likely to be keeping prices around US$70/b – a level that should stabilise internal finances and budgets for most member countries. 

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June, 13 2021
M & A in the US Shale Patch

It is only 5 months into 2021, and already Bloomberg estimates that merger and acquisition (M&A) activity in the US shale patch has more than doubled over the equivalent period in 2020 to over US$10 billion. Given that Covid lockdowns sapped energy from shale drilling from March 2020 and what was left was decimated again in April 2020 when US WTI prices (briefly) collapsed into negative territory. From this point onwards, it may not take much to maintain this doubling of M&A activity in the US shale patch over the next 7 months. But don’t call this a new trend; call it what it is: the inexorable centralisation of US shale as the long freewheeling Wild West years give way to corporate consolidation.

Even before Covid had been unleashed upon an unsuspecting world, this consolidation was already in full swing. When the US shale revolution first began accelerating in the early 2010s – when crude oil prices were high and acreage was cheap – there were thousands, maybe even tens of thousands, of small independent drillers vying alongside medium and large upstreamers busy striking riches across American shale basins such as Bakken, Eagle Ford, Marcellus and, of course, the Permian. But too many cooks spoiled the soup. The US shale drillers who were acting capitalistically without concern for discipline incurred the wrath of OPEC and caused the oil price bust in 2014/2015. For larger players were deep pockets and wide portfolios, the shock could be absorbed. But for the small, single field or basin players, it was bankruptcy staring them in the face. The sharp natural productivity dropoff of shale fields after initial explosive output meant profits had to be made super quick and super fast; if debt kept mounting up, then drillers must keep pumping to merely stay alive. But there is another option: merge or acquire. And so those thousands of players started dwindling down to hundreds.

But it wasn’t enough. Even though crude prices began to recover from 2016, it never again reached the dizzying levels of the boom years. Debt accumulated turned into debt to be repaid. And the financial community got wiser. Instead of being blinded by the promise of shale volumes, investors and shareholders started demanding value and dividends. Easy capital was no longer available to a small shale driller. And because of that no new small shale drillers emerged. Instead, the big boys arrived. Because shale oil and gas still held vast potential, the likes of ExxonMobil, Shell and Chevron started moving in. ExxonMobil went as far as calling the Permian its ‘future’ (though this was in the days before its super discoveries in Guyana were announced). With consolidation came cohesion. Instead of a complicated patchwork of small plots, a US shale operator’s modus operandi was now to look to its left or right for land that someone else owned which could be stitched up into its own acreage forming a contiguous asset. And so those hundreds of players started becoming dozens.

In late 2020, this drive ratcheted up as the prolonged Covid-caused fuels depression freed up plenty of candidates for deep-pocketed players. ConocoPhillips bought Concho Resources for US$9.7 billion. Pioneer Natural Resources snapped up Parsley Energy for US$4.5 billion. Chevron closed its US$5 billion acquisition of Noble Energy (after failing to acquire Anadarko after being outbidded by Occidental Petroleum in 2019), while Devon Energy snapped up WPX Energy for US$2.56 billion. All four were driven by the same motive – to expand foothold and stitch up shale assets (particularly in the Permian). This series of M&As rejigged the power balance in the Permian, propelling the four buyers into the top eight producers in the basin, joining Occidental, EOG, ExxonMobil and Chevron. These top eight Permian producers now have output of over 250,000 b/d, accounting for nearly 60% of the basin’s 4.5 mmb/d output.

You would think that this trend would continue until the Permian Big Eight became the Permian Big Four for Five. And this could still happen. But the latest M&A activity from a major Permian player suggests that the ambition may well be too constrained. Cimarex Energy, the tenth largest player in the Permian with output of some 100,000 b/d, just entered into a merger to create a US$17 billion Houston-based shale driller. But its partner was not, say, fellow Permian buddy SM Energy (80,000 b/d) or Ovintiv (75,000 b/d). Instead, Cimarex chose Cabot Oil & Gas, a gas-focused player that operates almost entirely in the Marcellus shale basin in Appalachia, over 1500km away from the Permian.

In response to the merger, share prices of both Cimarex and Cabot fell. Analysts cited a dilution of each company’s core focus (along with the meagre premium) as concerns; implying that investors would be happier if Cimarex stayed and grew in the Permian, and Cabot did the same in Marcellus. But that’s a narrow way of thinking that both Cimarex and Cabot were happy to refute. “This is a long term move,” said Cimarex CEO Tom Jorden. “This combination allows us to be ready for those (swings in commodity prices)”.

While pursuing in-basin opportunities could make shareholders happy in the short-term, a multi-basin deal might be a surprise but is also a canny long-term move. After all, at some point the Permian will run out of oil. And so will gas in Marcellus. Or the US government could accelerate its move away from fossil fuels. If an energy company puts all of its eggs into one basket – or basin, in this case – then when the river runs dry, the company’s profits evaporate. It is a consideration that other single-basin focused players like Pioneer, EOG and Diamondback will need to start thinking about, which is a luxury that other integrated players with Chevron and ExxonMobil already have. Consolidation in American shale basins is inevitable. But what is far more interesting is the new potential of cross-basin consolidation.

Market Outlook:

  • Crude price trading range: Brent – US$67-69/b, WTI – US$64-66/b
  • Global crude oil prices remain locked in their current ranges, with bullish signs of fuels demand recovery in North America, Europe and China offset by signs that the Iranian nuclear deal could be revived, which would lead increase OPEC supply
  • Iran, if reports are accurate, has already been preparing for this, establishing contact with former clients to gauge interest and pave way for its re-entry to the global oil markets, which could swell OPEC production by nearly 4 mmb/d
  • This will be a point of contention within the OPEC+ supply deal framework, since Iran would argue for exemptions (as Russia, Kazakhstan and Libya have) from official quotas; although the latest rhetoric from Iran suggests there are still plenty of gaps to restore the original 2015 nuclear agreement, allaying fears of a quick ramp-up
June, 08 2021
The Power of the Shareholders in Climate Change

The battle for the future of humanity is moving from the oceans and the rainforests of the world into the board rooms of the world’s largest energy companies. On a single day in late May, shareholders and courts delivered a decisive twist in the drive for the oil and gas industry to ‘go green’. Shell was ordered to cut its emissions by far more than it already plans to. Chevron’s stock holders defied the company’s recommendation by directing it to slash emissions. And ExxonMobil’s CEO went head-to-head with a small activist investor, which resulted in an embarrassing show for Darren Woods as he lost two seats on the Board of Directors. Serious and stoic newspapers called it ‘Black Wednesday for Big Oil’, representing a shift in the way the industry engages climate change: doing something just isn’t enough, and activists are ready to use the world’s courts and the companies’ own AGMs to force a change if none is coming.

In the Netherlands, a court ruled that Shell must slash its greenhouse gas emissions by 45% by 2030 (compared to 2019 levels) to bring it in line with the goals of the Paris Agreement. The case, by Friends of the Earth Netherlands, argues that Shell violates fundamental human rights by not accelerating its plans to slash emissions, jeopardising the Agreement’s target of limiting the average increase in global temperatures to less than 1.5 degrees Celsius. Not that Shell was a laggard in that arena. Like its other European energy peers, Shell has embarked on a strategy to reduce net emissions by 25% through 2030, and then to net-zero by 2050. That, the court said, is not enough. Shell needs to slash its emissions harder and faster than planned. And not just in the Netherlands, since the ruling applies to the entire Royal Dutch Shell Group, from Mexico to Malaysia. Shell will be appealing the ruling, potentially dragging the case through years of continued litigation, but the landmark decision will embolden more environmental groups to push for judicial action. There are currently some 1800 lawsuits related to climate court pending globally; prior to the Shell ruling, many were ruled in favour of energy companies, but this case could have a powerful ripple effect. At risk will be oil and gas companies in North America and Europe, but even national oil firms or players in developing countries are not safe, with cases also being filed in India, South Africa and Argentina.

However, the judicial process is a long and complicated one. Sometimes, it is faster than change things from the inside. And that is exactly what Chevron’s shareholders did at its recent AGM. Going against recommendations by Chevron’s own board, some 61% of investors voted for a proposal to reduce its Scope 3 greenhouse gas emissions – which is pollution caused by third-party use of its products. A sober CEO Mike Wirth went on Bloomberg to state that ‘interests in these (climate change) issues has never been higher and I think the votes reflects that.’ He shouldn’t have been surprised; a week earlier, 58% of ConocoPhillips shareholders also rejected company recommendations to vote for a similar full-scope emissions reduction target.

But even this pales in comparison to the drama that took place in the (virtual) boardroom of the world’s largest supermajor. It was a drama that began back in December 2020, when a small activist investor with only a 0.02% stake in ExxonMobil began lobbying the firm to take the fight against global warming more seriously. Initially dismissed, Engine No. 1 eventually proposed four of its own candidates to sit on ExxonMobil’s 12-strong Board of Directors, which includes CEO Darren Woods. ExxonMobil reportedly refused to meet with any of the 4 nominees, calling them ‘unqualified’ and that the activist’s goals would ‘derail our progress and jeopardise your dividend.’ That imperious approach rankled. Two prominent shareholder-advisory firms – Institutional Shareholder Services Inc and Glass Lewis & Co – then provided the activist partial support. ExxonMobil retaliated by stating that it would name two new directors, one with energy industry and one with climate experience, to quell dissent.

It was not enough. With ExxonMobil’s top three investors (Vanguard Group, BlackRock Inc and State Street Corp, collectively holding more than 21% of shares) wavering, the company made an unprecedented last-ditch attempt to prevent a defeat. Individual calls were made in a targeted manner to persuade a changing of votes, up until the virtual meeting started. After the AGM began, there even was a 60-minute pause citing volumes of votes incoming, during which some shareholders were contacted again to change their votes. In the words of one major executive, the move was ‘unprecedented’. Engine No. 1 publicly complained of the ‘banana republic tactic’ on television. But, in the end, two of its nominees – former CEO of refiner Andeavor Gregory Goff and environmental scientist Kaisa Hietala – were nominated to the Board. Two seats remain undecided, potentially granting Engine No. 1 a third director.

This rebuff was particularly painful for ExxonMobil and Chevron, who (along with other American majors) have been dragging their feet on climate change. Their gamble to focus on shorter-term profits generated by higher crude prices and prodigious production, while only evolving their sustainability position gradually, had long been thought to please shareholders. Apparently not. Climate change affects all, including some of the world’s largest investors like BlackRock Inc, which has been very vocal about its climate position. So if ExxonMobil’s executives won’t take climate change seriously, then change must be forced at the Board level. This may put Darren Woods in a wobbly position; but so far Engine No. 1 has not shown signs of wanting to oust Woods, they just want climate change to be a stronger item on his agenda.

But even if climate change is already a major item, that might not be enough, as seen in the ruling against Shell. Even the most ambitious of the supermajors like BP and Total (which was just rebranded to TotalEnergies) might not be safe from litigation, even though their decarbonisation plans were rated as the best by financial thinktank Carbon Tracker. Which could be the reasoning behind some recent moves by the supermajors to start shedding traditional assets and acquiring renewable ones: ExxonMobil has decided to pull out of a deepwater oil prospect in Ghana, Shell has decided to sell its Mobile Chemical LP refinery in Alabama to Vertex Energy Operating and its Deer Park Refining stake to Pemex, while BP has just acquired 9GW of renewable energy capacity in the USA from 7X Energy as its chases a global 50GW goal by 2030. Taken together, these moves are creating a narrative. Boardrooms and AGMs are generally safe places for energy executives, but not anymore. The new era is upon the energy industry. And the definition of ‘good enough’ has just changed.

End of Article

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Market Outlook:

  • Crude price trading range: Brent – US$69-71/b, WTI – US$66-68/b
  • Brent crude prices topped the US$70/b mark, signalling strength in oil with consumption in the US, Europe and China rebounding strongly and OPEC+ signalling that the supply side was beginning to tighten
  • That declaration by OPEC+ will undoubtedly lead to a further easing of the club’s supply quotas from July onwards, as it aims to balance stable oil prices with steady supply that will not overwhelm the market, even with Iran’s possible return
  • The timeline and momentum for Iran to restore production – potentially to 4-5 mmb/d from a current 2.5 mmb/d – will depend on ongoing talks to revive the 2015 nuclear accord, but Iran has already started laying the groundwork for an inevitable return 

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June, 02 2021