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. 

Get timely updates about latest developments in oil & gas delivered to your inbox. Join our email list and get your targeted content regularly for free.

Submit Your Details to Download Your Copy Today

Learn more - here

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