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Last Updated: December 14, 2018
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Market Watch

Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b

  • Crude prices strengthened at the start of this week, with OPEC delivering an agreement that will see production across the OPEC+ alliance decline by 1.2 mmb/d beginning January 2019
  • Two-thirds or 800,000 b/d of the cut will be borne by OPEC – with most of it taken up by Saudi Arabia – while the non-OPEC group will take up a cut of 400,000 b/d, most of which will be taken up by Russia
  • Skepticism has reigned before the supply deal was reached, as the first day of the OPEC meeting in Vienna closed without consensus and the threads holding OPEC together showed some stress when Qatar decided to quit the group
  • Crude prices were also boosted by Libya declaring force majeure at its largest oil field at El Sharara over arm protests, while Canada’s Alberta province announced plans to pare back some 325,000 b/d of output to ease a huge glut
  • The coordinated supply deal by OPEC ‘was not easy’ according to UAE Minister of Energy and Industry, with Iran in particular balking at being asked to sign up to a symbolic cut; this might not augur well for future supply deals that might be necessary given current trends
  • However, the supply cut will only last until April 2019, when the terms are due for a review, which would give OPEC+ enough time to consider and deal with the expiration of American waivers for eight countries over continued import of Iranian crude in May
  • Meanwhile, America became a net oil exporter for the first time in almost 75 years, as the unprecedented boom in US crude oil fuelled by the shale revolution powers on, a development that could dilute OPEC+’s attempt to support global crude prices
  • The recent weakening of WTI prices saw the US lose 10 active oil rigs last week, however, the addition of 9 new gas rigs led to a net loss of only 1 in the Baker Hughes active US rig count
  • Crude price outlook: OPEC+’s decision might have provided some relief, but may not be enough to keep crude oil prices trending upwards. Expect prices to moderate to US$60-61/b for Brent and US$50-51/b for WTI

Headlines of the week

Upstream

  • ExxonMobil’s winning streak in Guyana continues, as it announces its 10th offshore discovery at the Pluma-1 well, boosting estimated recoverable resources in the Stabroek block by almost 1 mmb/d to over 5 mmb/d
  • Apache has initiated production at the Garten field in the UK North Sea, with an output rate of 13,700 b/d and 15.7 bcf/d of natural gas
  • Chevron has raised its capital expenditure for the first time since 2014 into US$20 billion, with a major focus on expanding operations in the Permian Basin as well as on the Tengiz megaproject in Kazakhstan
  • Canada’s Alberta province, weighed down by a supply glut caused by pipeline bottlenecks, has announced moves to reduce the region’s output by 325,000 b/d
  • Equinor and Faroe Petroleum have agreed to trade a number of assets in the Norwegian Sea and the Norwegian Continental Shelf North Sea, encompassing the Njord, Bauge Hyme, Vilje Ringhome, Marulk and Alve fields, with the deal described as a ‘balanced swap’ in terms of value with no cash consideration

Downstream

  • CNPC’s US$9.53 billion joint venture integrated 400 kb/d petrochemicals/refinery project with PDVSA in Jieyang, China has been reactivated, and is now expected to begin operations in late 2021
  • French president Emmanuel Macron has backtracked and suspended a planned fuel-tax hike, after weeks of violent riots by the so-called Yellow Vests grassroot groups of up to 300,000 protestors
  • Limetree Bay Ventures has secured US$1.25 billion in financing that paves the way for the Limetree Bay refinery in the US Virgin Islands to restart after being idled for years, partnering with BP Products North America on the project

Natural Gas/LNG

  • Equinor has received permission from the Norwegian government to proceed with the development of Troll Phase 3, delivering an additional 2.2 billion boe/d of natural gas with a planned start-up timeframe of 1H2021
  • Shell has completed the construction of Gibraltar’s first LNG regasification facility, a small-scale project that will feed a new power plant in the territory
  • Trinidad and Tobago has agreed to allow BP and Shell to extend the operational life of the Atlantic LNG Train 1 in Point Fortin by five years, with the country receiving the ability to sell LNG cargoes through its state gas firm
  • Tokyo Gas and the Philippines’ First Gen Corporation have signed a joint development agreement to build and operate an LNG receiving terminal, as the three-horse race narrows over the country’s first LNG import facility
  • American LNG player Tellurian has agreed to supply trader Vitol with some 1.5 mtpa of LNG over 15 years from its 27.6 mtpa Driftwood LNG export terminal currently being developed in Calcasiue River, Louisiana
  • Tanzania is opening talks with Equinor and ExxonMobil to launch the East African nation’s first LNG project, likely to derive gas from the Equinor-operated offshore Block 2
  • Shell is expecting to produce its first cargo of LNG from its Prelude FLNG facility in Australia before the end of 2018

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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