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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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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
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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The New “Militia” In Oil & Gas Operations

On 7 May 2021, a most unusual occurrence took place in the USA. The Colonial Pipeline – which carries gasoline, jet fuel and other refined products from Houston to New York across the Southeastern and Eastern United States – halted all operations, triggering a fuel distribution panic. As the largest pipeline system for refined fuels in the US, capable of carrying up to 3 million barrels of fuel per day, the closure of the pipeline triggered some perplexing scenes – from the hoarding of gasoline in plastic bags to a lady expressing her reliance on gasoline to survive on TV despite her SUV being emblazoned with a ‘Say No To Pipelines’ sticker.

The panic lasted five days until 12 May, when portions of the pipeline were restarted. But what is far more worrying is why it happened. This was not the result of an act of nature that created a force majeure, or because of a structural fault that ruptured the operation of the pipeline. No, the Colonial Pipeline outage of May 2021 was a cyberattack. Hackers, believed to be from Eastern Europe, had infiltrated the Colonial Pipeline Company’s IT systems, triggering a cyberattack that impacted the computerised equipment managing 45% of all fuels delivered to the US East Coast. In response to the attack, Colonial Pipeline halted its entire operations to contain the situation, while dealing with the hackers’ ransomware demand of 75 bitcoins, which is worth almost US$5 million at current exchange rates.

Ransomware cyberattacks are not new, having been around since the internet first gained widespread use in the 1990s. But the sophistication of these attacks has increased, especially since corporate IT security systems have not kept pace with hacking techniques. But this is certainly the first large-scale and highest-profile cyberattack on American and global energy infrastructure, offering a nervous look at just how secure the crucial worldwide energy complex is, and how this should and must be improved before even larger cyberattacks are launched.

Because gone are the days when the pipeline disruptions had to be physical – whether it was Boko Haram militia sabotaging crude pipelines in Nigeria or undetected defects triggering spillages in the US-Canada Keystone pipeline. With much of the pipeline’s controls now done from a screen in an air-conditioned office, ill intent does not have to travel to a wet marshland to cause chaos. A simple backdoor vulnerability could give a malicious individual or group full access to a company’s inner system workings, to devastating consequences. This was exactly what happened to Colonial Pipeline, with the group responsible believed to have stolen over 100 gigabytes of data from company servers before Colonial even had a clue. And this is not unique to Colonial Pipeline. In fact, the risk is so widespread as to be alarming. Risk specialist and advisor Marsh has stated that the ‘global energy sector is increasingly vulnerable to cyber-attacks and hacking, due to widespread adoption of internet-based, or ‘open’, industrial controls systems to reduce costs, improve efficiency and streamline operations. The nature of the threat is beginning to change, and virtually all industry sectors have begun to witness much more intelligent and complex attacks.’ The dependence on common IT platforms and standards has certainly been to boon to business – a far cry from the 1980s and 1990s were each company tended to maintain its own proprietary systems – but that standardisation is also a major vulnerability. One backdoor identified by hackers is a backdoor into thousands of companies.

So major was this cyberattack that the Biden administrative pulled together an inter-agency task force over that weekend to address the breach, mitigate the impact and assess the wider scale of vulnerabilities across the US energy sector. The first two were handled deftly and quickly, but the last will take years. Meanwhile, the cat is out of the bag now. Because, despite publicly refuting it previously, Colonial Pipeline actually paid the ransom. And it paid it on the day of the outage itself (May 7) through bitcoin, which is beloved by hackers for its untraceability. Once paid, the hackers – thought to be a new group known as DarkSide – provided Colonial with a decrypting tool to restore its disable network, but the provide so slow that it took over five days for full services to be restored.

Paradoxically, though, the cyberattack has actually increased the average American’s opinion of oil and gas pipelines now that the disruption of a major one became so apparent, at least based on early polling. This could herald a shift in the position of the current US government regarding domestic pipeline infrastructure, moving away from demonising it to investing in it (or at least existing ones) if only to secure them against cyber-threats. And maybe, possibly, even soften Joe Biden’s stance on new projects, including Keystone XL?

In a statement posted on its dark webpage, DarkSide stated that it would vet ‘customers’ in the future to ‘avoid social consequences’. Which is all good and well, but the fact that the cyberattack was successful in the first place, and that Colonial Pipeline actually paid the ransom (against all FBI and federal advice) could mean a cyberattack frenzy in the near future. A few lines of code, a savvy hacker and an unknown vulnerability could yield millions of dollars in untraceable crypto-currencies. IT and risk departments across all energy companies worldwide must be quaking in their boots. Because the threat of cyberterrorism and ransomware is now ever-present and ever-dangerous, from Texas to Thailand, New York to Nigeria. In May 2021, it was the largest refined fuels pipeline in the US. It could be a rig, a cargo ship or even an entire refinery tomorrow.

End of Article

Market Outlook:

-  Crude price trading range: Brent – US$67-69/b, WTI – US$64-66/b

-  Steady is the global crude oil price ship, with benchmark contracts staying stable in their ranges on demand recovery in key consumption regions (US, Europe and China) smoothing over the asymmetrical global recovery as Covid-19 continues to flare up in South Asia, and even previously safe spots Taiwan, Singapore and Japan

-  A new chapter of Israeli-Palestine violence may begin to add risk premiums to crude trading on the potential on infrastructure disruptions in the Middle East and a potential reset of Israel’s relationship with new allies like the UAE and Bahrain

End of Article

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SHORT-TERM ENERGY OUTLOOK

Forecast Highlights

Global liquid fuels

  • The May Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Economic activity has increased significantly after reaching multiyear lows in the second quarter of 2020. The increase in economic activity and easing of COVID-19-related restrictions have contributed to rising energy use. U.S. gross domestic product (GDP) declined by 3.5% in 2020 from 2019 levels. This STEO assumes U.S. GDP will grow by 6.2% in 2021 and by 4.3% in 2022. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit. Our forecast assumes continuing economic growth and increasing mobility with easing COVID-19-related restrictions, and any developments that would cause deviations from these assumptions would likely cause energy consumption and prices to deviate from our forecast.
  • We completed modeling and analysis for this report before the temporary closure of the Colonial Pipeline on May 7 as a result of a cyberattack. Although effects of the outage are not reflected in this report, we are closely following supply and price developments related to the outage. Updates related to the outage will be reflected in Today in EnergyThis Week in Petroleum, and the Weekly Petroleum Status Report as they become available.
  • Brent crude oil spot prices averaged $65 per barrel (b) in April, unchanged from the average in March. Brent prices were steady in April as market participants considered diverging trends in global COVID-19 cases. In some regions, notably the United States, oil demand is rising as both COVID-19 vaccination rates and economic activity increase. In other regions, notably India, oil demand is declining because of a sharp rise in COVID-19 cases. EIA forecasts that Brent prices will average $65/b in the second quarter of 2021, $61/b during the second half of 2021, and $61/b in 2022.
  • We estimate that the world consumed 96.2 million barrels per day (b/d) of petroleum and liquid fuels in April, an increase of 15.8 million b/d from April 2020 but 4.0 million b/d less than April 2019 levels. We forecast that global consumption of petroleum and liquid fuels will average 97.7 million b/d for all of 2021, which is a 5.4 million b/d increase from 2020. We forecast that consumption of petroleum and liquid fuels will increase by 3.7 million b/d in 2022 to average 101.4 million b/d.
  • We expect that gasoline consumption in the United States will average almost 9.0 million b/d this summer (April–September), which is 1.2 million b/d more than last summer but almost 0.6 million b/d less than summer 2019. We increased our summer gasoline consumption forecast by 0.1 million b/d from last month based on weekly data that suggested more gasoline consumption than we had previously forecast. The increase also reflects IHS Markit’s increased employment forecast. For all of 2021, we forecast that U.S. gasoline consumption will average 8.7 million b/d, which is up from 2020 (8.0 million b/d) but down from 2019 (9.3 million b/d).
  • According to our most recent data, U.S. crude oil production averaged 9.9 million b/d in February 2021, which was down by 1.2 million b/d from January. In February, cold temperatures caused significant declines in crude oil production in Texas, as well as smaller declines in other states. We estimate that production outages were generally limited to February and that U.S. crude oil production rose to 10.9 million b/d in March and to almost 11.0 million b/d in April. Because the average price of West Texas Intermediate crude oil remains above $55/b in our forecast, we expect producers will drill and complete enough wells in the coming months to offset declines at existing wells. In addition, new projects in the Federal Offshore Gulf of Mexico contribute to rising production in the forecast. U.S. crude oil production in the forecast averages 11.3 million b/d in the fourth quarter of 2021 and then rises to average 11.8 million b/d in 2022.

Natural Gas

  • In April, the natural gas spot price at Henry Hub averaged $2.66 per million British thermal units (MMBtu), which is slightly higher than the March average of $2.62/MMBtu. We expect the Henry Hub spot price will average $2.78/MMBtu in the second quarter of 2021 and will average $3.05/MMBtu for all of 2021, which is up from the 2020 average of $2.03/MMBtu. We expect natural gas prices will rise this year, primarily as a result of two factors: growth in liquefied natural gas (LNG) exports and rising domestic natural gas consumption in the residential, commercial, and industrial sectors. In 2022, we expect the Henry Hub price will fall to an average $3.02/MMBtu amid slowing growth in LNG exports and rising production.
  • We expect that U.S. consumption of natural gas will average 82.6 billion cubic feet per day (Bcf/d) in 2021, down 0.7% from 2020. U.S. natural gas consumption declines in the forecast, in part, because electric power generators switch to coal from natural as a result of rising natural gas prices. In 2021, we expect residential and commercial natural gas consumption together will rise by 1.0 Bcf/d from 2020 and industrial consumption will rise by 0.8 Bcf/d from 2020. Rising consumption outside of the power sector results from expanding economic activity and colder temperatures in 2021 compared with 2020. We expect U.S. natural gas consumption will average 82.5 Bcf/d in 2022.
  • We estimate that natural gas inventories ended April 2021 at almost 2.0 trillion cubic feet (Tcf), which is 3% lower than the five-year (2016–20) average. Natural gas withdrawals from storage during the winter of 2020–21 were higher than the five-year average, largely as a result of the cold February temperatures that contributed to a drop in natural gas production. We forecast that natural gas inventories will end the 2021 injection season (end of October) at more than 3.6 Tcf, which is 3% below the five-year average.
  • We forecast that U.S. production of dry natural gas will average 91.1 Bcf/d in 2021, which is down 0.3% from 2020. Dry natural gas production fell by 6.0 Bcf/d in February to 86.3 Bcf/d because of cold weather that largely affected Texas. We estimate production increased to 91.3 Bcf/d in March. We expect relatively flat dry natural gas production in May ahead of production beginning to rise in mid-2021. We forecast dry natural gas production will reach 92.0 Bcf/d in the fourth quarter of 2021 and average 93.1 Bcf/d in 2022. The increase in production reflects sustained higher forecast prices for natural gas and crude oil compared with 2020.
  • U.S. LNG exports set an all-time record in March 2021 at 10.5 Bcf/d and averaged 9.2 Bcf/d in April—the most exported LNG for those months since the United States began exporting it in 2016. Throughout 2020 and in January 2021, more than half of U.S. LNG exports went to Asia. However, in February and March 2021, more than half of U.S. LNG exports went to Europe as a result of spot natural gas prices in Europe reaching levels similar to spot natural gas prices in Asia. For May, we forecast a decline in U.S. LNG exports to 8.6 Bcf/d (more than 90% of baseload export capacity utilization) before exports rise above 9.0 Bcf/d in the summer months to meet summer peak demand in Europe and Asia. We expect LNG exports will average 9.2 Bcf/d in both 2021 and 2022, up from 6.5 Bcf/d in 2020. Flat LNG exports in 2022 reflect our expectation that limited new export capacity will come online during the forecast period.

U.S. natural gas prices


Electricity, coal, renewables, and emissions

  • We forecast that electricity consumption in the United States will increase by 2.2% in 2021 after falling 3.9% in 2020. We forecast electricity sales to the industrial sector will grow by 3.3% in 2021. We forecast that retail electricity sales to the residential sector will grow by 2.9% in 2021, which is primarily a result of colder temperatures in the first quarter of 2021 compared with the same period in 2020. We expect retail electricity sales to the commercial sector will increase by 1.4% in 2021. Much of the increased electricity consumption across the sectors reflects improving economic conditions in 2021. For 2022, we forecast that U.S. electricity consumption will grow by another 1.0%.


World liquid fuels production and consumption balance