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Last Updated: February 10, 2021
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Forecast Highlights

  • The February Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty because responses to COVID-19 continue to evolve. Reduced economic activity related to the COVID-19 pandemic has caused changes in energy demand and supply over the past year and will continue to affect these patterns in the future. U.S. gross domestic product (GDP) declined by 3.6% in 2020 from 2019 levels. This STEO assumes U.S. GDP will grow by 3.8% in 2021 and by 4.2% in 2022. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit.
  • Brent crude oil spot prices averaged $55 per barrel (b) in January, up $5/b from the December average but $9/b lower than the average in January of last year. Higher Brent prices in January largely reflected the January 5 announcement by Saudi Arabia that it would unilaterally cut 1.0 million barrels per day (b/d) of crude oil production in February and March, in addition to the reduced production levels on which the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) previously agreed. The U.S. Energy Information Administration (EIA) expects Brent crude oil prices will average $56/b in the first quarter of 2021 and $52/b over the remainder of the year. EIA expects lower oil prices later in 2021 as a result of rising oil supply that will slow the pace of global oil inventory withdrawals. EIA also expects that high global oil inventory levels and spare production capacity will limit upward price pressures. EIA expects Brent prices will average $55/b in 2022.
  • EIA estimates that the world consumed 93.9 million b/d of petroleum and liquid fuels in January, which is down 2.8 million b/d from January 2020. EIA forecasts that global consumption of petroleum and liquid fuels will average 97.7 million b/d for all of 2021, which is up by 5.4 million b/d from 2020. EIA forecasts that consumption of petroleum and liquid fuel will increase by 3.5 million b/d in 2022 to average 101.2 million b/d.
  • EIA estimates that U.S. crude oil production averaged 11.0 million b/d in January, which is down slightly from 11.1 million b/d in November (the most recent month for which historical data are available). EIA expects production will continue to decline slightly in the coming months, reaching 10.9 million b/d in June. Although oil-directed drilling has increased in the United States in recent months, the number of active drilling rigs remains lower than year-ago levels. EIA expects production from newly drilled wells will be more than offset by declining production rates at existing wells in the first half of 2021. However, based on EIA’s forecast that West Texas Intermediate crude oil prices will remain near or higher than $50/b during the forecast period, EIA expects drilling will continue to increase. As a result, production from new wells will exceed the declines from legacy wells, and overall crude oil production will increase in the second half of 2021 and in 2022. EIA estimates that U.S. crude oil production will average 11.0 million b/d in 2021—down from 11.3 million b/d in 2020 and 12.2 million b/d in 2019—and will rise to 11.5 million b/d in 2022.
  • U.S. regular gasoline retail prices averaged $2.33 per gallon (gal) in January, compared with an average of $2.20/gal in December and $2.55/gal in January 2020. EIA forecasts gasoline prices to average $2.44/gal in 2021 and $2.46/gal in 2022. U.S. diesel fuel prices averaged $2.68/gal in January compared with $2.58/gal in December and $3.05/gal in January 2020, and EIA forecasts it will average $2.70/gal in 2021 and $2.77/gal in 2022.
  • On a volume basis, U.S. consumption of gasoline declined by more than other petroleum products in 2020. EIA forecasts that U.S. gasoline consumption will rise in the forecast but remain lower than 2019 levels. U.S. gasoline consumption is forecast to average 8.6 million b/d in 2021 and 8.9 million b/d in 2022, up from 8.0 million b/d in 2020 but lower than the 9.3 million b/d consumed in 2019.
  • EIA expects that total U.S. consumption of natural gas will average 81.7 billion cubic feet per day (Bcf/d) in 2021, down 1.9% from 2020. The decline in total U.S. consumption reflects less natural gas consumed for electric power as a result of higher natural gas prices compared with last year. In 2021, EIA expects residential natural gas demand to average 12.9 Bcf/d (up 0.2 Bcf/d from 2020) and commercial demand to average 9.1 Bcf/d (up 0.6 Bcf/d from 2020). EIA forecasts industrial consumption will average 23.0 Bcf/d in 2021 (up 0.4 Bcf/d from 2020) as a result of increased manufacturing activity amid a recovering economy. Industrial consumption of 23.0 Bcf/d would be 0.1 Bcf/d below the 2019 level. EIA expects total U.S. natural gas consumption will average 81.0 Bcf/d in 2022.
  • In January, the Henry Hub natural gas spot price averaged $2.71 per million British thermal units (MMBtu), up from the December average of $2.59/MMBtu. EIA expects Henry Hub spot prices to reach a monthly average of $2.98/MMBtu in February 2021. Higher expected prices in February reflect expectations of continued strong liquefied natural gas (LNG) exports and a shrinking surplus of natural gas in storage compared with the five-year (2016–20) average. EIA uses weather forecasts from the National Oceanic and Atmospheric Administration (NOAA) as an input into the STEO, and the NOAA forecast in this STEO is from late January. More recent forecasts for mid-February weather show cold temperatures could extend across much of the United States, which creates an upside risk to near-term prices in this outlook. EIA expects that Henry Hub spot prices will average $2.95/MMBtu in 2021, which is up from the 2020 average of $2.03/MMBtu. EIA expects that continued growth in LNG exports and in domestic natural gas consumption outside of the electric power sector, as production remains relatively flat, will contribute to Henry Hub spot prices rising to an average of $3.27/MMBtu in 2022.
  • U.S. working natural gas in storage ended October at more than 3.9 trillion cubic feet (Tcf), 5% more than the 2015–19 average and the fourth-highest end-of-October level on record. EIA estimates that inventory withdrawals were 703 billion cubic feet (Bcf) in January, compared with a five-year (2016–20) average January withdrawal of 716 Bcf. The January withdrawals occurred at a lower rate than EIA forecast in last month’s STEO. The lower-than-expected withdrawal is the result of warmer-than-average January temperatures that reduced natural gas use for space heating. However, EIA forecasts that declines in U.S. natural gas production this winter compared with last winter will more than offset the declines in natural gas consumption, which will contribute to natural gas storage returning to levels near the five-year average by the end of winter. Forecast natural gas inventories end March 2021 at 1.8 Tcf, which is about the same as the five-year average.
  • EIA forecasts that U.S. production of dry natural gas will average 90.5 Bcf/d in 2021 and 91.0 Bcf/d in 2022, which are down from an average of 91.3 Bcf/d in 2020 and 93.1 Bcf/d in 2019. In the forecast, dry natural gas production remains relatively flat, averaging between 89.8 Bcf/d and 91.0 Bcf/d in every month from February 2021 through July 2022. Flat natural gas production is the result of falling production in several of the smaller natural gas producing regions being offset by growth in other regions, most notably in the Appalachia and Haynesville regions.
  • EIA estimates that the United States exported 9.8 Bcf/d of LNG in January amid high spot natural gas prices in Asia. However, foggy conditions and high winds affected export operations at Sabine Pass LNG, Corpus Christi LNG, and Cameron LNG, leading to several weather-related closures and sporadic suspension of piloting services on several days in January. EIA forecasts that U.S. LNG exports will average 8.5 Bcf/d in 2021. In 2022, EIA forecasts LNG exports will average 9.2 Bcf/d, surpassing the amount of natural gas exported via pipeline for the first time.
  • EIA forecasts that consumption of electricity in the United States will increase by 1.6% in 2021 after falling 3.8% in 2020. EIA forecasts residential sector retail sales will grow by 2.2% in 2021. The increase is primarily a result of colder forecast temperatures in the first quarter of 2021 compared with the same period in 2020, which EIA expects will raise demand for space heating, along with EIA’s assumption that more people will be working from home than in the first quarter of 2020. EIA expects retail sales of electricity in the commercial and industrial sectors will increase by 1.2% and 2.3%, respectively. For 2022, EIA forecasts total electricity consumption will grow by another 1.7%.
  • EIA expects the share of U.S. electric power generated with natural gas to fall from 39% in 2020 to 37% in 2021 and to 35% in 2022. The forecast natural gas share declines in response to a forecast increase in the price of natural gas delivered to electricity generators from an average of $2.38/MMBtu in 2020 to $3.27/MMBtu in 2021 (a 37% increase). Coal’s forecast share of electricity generation rises from 20% in 2020 to 21% in 2021 and to 22% in 2022. Electricity generation from renewable energy sources rises from 20% in 2020 to 21% in 2021 and to 23% in 2022. The nuclear share of U.S. generation declines from 21% in 2020 to 20% in 2021 and to 19% in 2022.
  • EIA forecasts that planned additions to U.S. wind and solar generating capacity in 2021 and 2022 will contribute to increasing electricity generation from those sources. EIA estimates that the U.S. electric power sector added 17.5 gigawatts (GW) of new wind capacity in 2020. EIA expects 15.3 GW of wind capacity will be added in 2021 and 3.6 GW in 2022. Utility-scale solar capacity rose by an estimated 11.1 GW in 2020. The forecast for added utility-scale solar capacity is 16.2 GW for 2021 and 12.3 GW for 2022.
  • EIA expects U.S. coal production to total 589 MMst in 2021, 50 MMst (9%) more than in 2020. In 2022, EIA expects coal production to rise by a further 5 MMst (1%). These increases reflect higher forecast demand for coal in the electric power sector because of rising natural gas prices, which increases coal’s competitiveness relative to natural gas for power generation dispatch. Although EIA expects coal production to rise in 2022, expected production increases will be limited by strong inventory draws. EIA expects significant coal supply to the power sector will come from a reduction in inventory levels in 2022, as the power sector brings inventory levels back in line with historical averages. Coal production in the forecast will also be limited by declining production capacity, as high mine reclamation costs have contributed to mine divestments and closings that may counter the effects of higher coal demand.
  • EIA expects rising global economic activity will contribute to rising steel production and power demand, which will lead to increased U.S. exports of both metallurgical and steam coal. EIA forecasts coal exports will total 85 MMst in 2021, up by 24% from 2020, which was the lowest level since 2016. EIA forecasts exports will rise by 6 MMst in 2022 to 91 MMst.
  • EIA estimates that U.S. energy-related carbon dioxide (CO2) emissions decreased by 11% in 2020. This decline in emissions is the result of less energy consumption related to economic contraction in response to the COVID-19 pandemic. In 2021, EIA forecasts that energy-related CO2 emissions will increase by about 4% from the 2020 level as economic activity increases leading to rising energy use. Energy-related CO2 emissions are also expected to rise by 3% in 2022 as economic growth continues. 

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What Stays, What Goes

It was a headline that definitely opened eyes and definitely perked up ears. News that supermajor Shell was in the process of reviewing its holdings in the largest US oil field – the onshore Permian basin – came as a shock. On one hand, why was Shell looking to sell off its assets in the prized US shale patch only months after naming it one of its nine ‘core’ upstream areas? On the other hand, the prospect of taking over Shell’s sizable acreage in the Permian has set its competitors operating in the same shale patch sniffing around for opportunities.

The answer to the former has been most influenced by a recent judgement at a court in The Hague, where Royal Dutch Shell is headquartered. The court ruled that Shell’s carbon plans – which calls for a reduction of greenhouse gas emissions to net zero by 2050 and an absolute 20% reduction by 2030 – was insufficient and not in line with the climate change goals of the Paris Agreement. Instead, the court ordered that Shell must reduce its emissions by 45% from 2019 levels by 2030, siding with environmental NGO Friends of the Earth which brought on the case by claiming that Shell was violating human rights with its current plan. Crucially, and unusually, the court applied the verdict to Shell’s entire global operations, spanning multiple jurisdictions, rather than limited to just Dutch holdings. Shell has announced plans to appeal, which could drag the process on for years in higher courts. But on the off-chance that this judgement remains binding, it is perhaps looking for ways to shave off carbon-intensive assets.

Why else would chatter suddenly surface that Shell was considering selling off its collection of prime Permian acreage located in the prolific Delaware basin? After all, just a few months ago in February, Shell announced that it was planning to reshape its upstream business to focus on nine core areas that generated 80% of its revenue – Brazil, Brunei, the Gulf of Mexico, Kazakhstan, Malaysia, Nigeria, Oman, the UK North Sea and, of course, the Permian Basin in the US. Although Shell is not among the largest Permian players, its 260,000 acres are still sizable and its output of some 60,000 b/d ranks Shell among the Permian’s 20 largest producers. Valuations suggest that the sale could fetch as much as US$10 billion, which is a lot of cash that Shell could redirect to clean energy initiatives if the aim is to conform to the court order. Because Shell is not exactly in fire-sale mode; its asset divestment program to hive off non-core assets to pay for its US$53 billion acquisition of BG Group in 2015 was already complete.

To be fair, for all the activity in the Permian, sustained profitability has proven elusive. Not just to Shell, but other major players there as well. The rapid drop-off in well productivity after the first two years means that players have to be constantly drilling and discovering, while a large-scale traditional crude oil field could last for decades after initial production. Shell is also not the only one to consider shedding assets; Chevron and ExxonMobil are also rumoured to be considering divestment as well. And why not? With crude prices at their highest point since late 2018, it is a good time to fetch the best price for oil assets. Most Permian deals in 2021 have closed at between US$7,000 and US$12,000 per acre – already a major increase from 2020 and 2019 – but Shell’s prime 260,000 acres acquired from Chesapeake Energy and Anadarko in 2012 would fetch a major premium, possibly almost as high as US$40,000/acre that would be in line with Pioneer Natural Resources’ acquisition of DoublePoint Energy in April 2021. Any sale would definitely exceed Shell’s initial investment of US$1.9 billion, fetching a tidy profit. Of course, the move would also shrink Shell’s US footprint, limiting it to the Gulf of Mexico (where the Whale field FID is expected soon) and a single oil refinery (Norco), after selling its stake in the Deer Park refining site to Pemex from an unsolicited bid.

If the sale goes through – and it is still a big if at this point – then Shell’s loss will be someone else’s gain. Who would that be? Potential bidders include ConocoPhillips, Devon Energy, Chevron, EOG Resources or even private equity firms that have not been scared off by the potential debt burden of Permian assets. Shell is likely to be looking for an all-cash deal for the entirely of the asset, but is reportedly open to also parcelling up the land into multiple packages. According to sources, a data room with full information on the assets has already been opened.

Looking at the location of Shell’s Permian assets, synergies exist with ConocoPhiliips and Chevron, which both own acreage close to the Shell holdings. Other potential buyers that operate in the Delaware region of the Permian include Occidental and EOG, with Devon Energy being the smallest company that could likely afford a purchase. But Occidental is still busy adjusting after outbidding Chevron in a blockbuster acquisition of Anadarko, which could preclude a purchase by Shell’s partner in its Permian operations. Pioneer Natural Resources might also be excluded as a potential buyer, given that it primarily focuses on the Midland region east of Delaware. But even if the desire is there, there are additional hurdles. Given the immense focus on climate change and the industries that contribute to it, capital is increasingly a challenge, since the financing of fossil fuels is under massive pressure.

Not that those hurdles are insurmountable. The pressures facing a supermajor like Shell – or even ExxonMobil and Chevron – do not necessarily apply in the same measure to other players. If Shell is willing to sell, then there will be plenty of willing buyers vying for the assets. But what is also certain is that recent climate change moves that are ongoing in the boardrooms of energy giants are starting to have very concrete implications and applications on operations. The heat fuelling merger and acquisition activity in the Permian is about to get a lot hotter.

Market Outlook:

  • Crude price trading range: Brent – US$72-74/b, WTI – US$70-72/b
  • Both global crude benchmarks – Brent and WTI – cross the US$70/b threshold, recording the highest level of crude prices since October 2018, as the market focuses on the sustained improvements in fuel demand heading into the crucial summer season in the normal atmosphere that typically boosts road and air travel
  • The outbreak of new Covid variants is still a concern, but the accelerating pace of vaccinations – even in the hardest-hit countries– are providing some reassurance that any current lockdowns will not be prolonged
  • OPEC+ is predicting that oil demand growth will jump by 5 mmb/d in the 2H21 from 1H21 levels, setting the stage for further easing of the OPEC+ supply quotas; Iran’s return to international crude markets is likely to be further afield as talks to revive the 2015 nuclear deal enter into roadblocks

End of Article

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June, 19 2021
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