Today's This Week in Petroleum articles were originally published throughout 2019. New feature articles of This Week in Petroleum will return on January 8, 2020. The retail price and inventory paragraphs, charts, and tables accompanying the feature article have been updated to reflect data from the latest Weekly Petroleum Status Report for the week ending December 27, 2019.
On Friday, June 21, the Philadelphia Energy Solutions (PES) 335,000 barrels per day (b/d) refinery in South Philadelphia experienced a major fire and explosion. The resulting damage to the refinery and preexisting financial strains led PES to announce its intention to shut down operations at the refinery. The closure of the Philadelphia refinery would decrease the number of operating East Coast refineries to seven and total operating capacity to 889,000 b/d (Figure 1). The U.S. Energy Information Administration (EIA) estimates closing the Philadelphia refinery would reduce East Coast gasoline supplies by approximately 160,000 b/d and distillate supplies by approximately 100,000 b/d. The potential shutdown of the largest refinery by capacity on the U.S. East Coast is likely to reconfigure petroleum product supply chains in the Central Atlantic.
(Published: July 17, 2019) The crude oil adjustment accounts for differences in supply and disposition
The U.S. Energy Information Administration's (EIA) Weekly Petroleum Status Report (WPSR) provides weekly estimates of U.S. crude oil supply, including a measure of how well the supply of crude oil and the disposition of crude oil balance with each other. This measure—referred to as the adjustment—is a derived term equal to the difference between supply and disposition. If the reported supply and disposition of crude oil balanced perfectly each week, the adjustment would equal zero. For several reasons, however, this is rarely the case.
(Published: September 18, 2019) Saudi Arabia crude oil production outage will affect global oil markets and U.S. gasoline prices
On Saturday, September 14, 2019, an attack damaged the Saudi Aramco Abqaiq oil processing facility and the Khurais oil field in eastern Saudi Arabia. The Abqaiq oil processing facility is the world's largest crude oil processing and stabilization plant with a capacity of 7 million barrels per day (b/d), equivalent to about 7% of global crude oil production capacity. On Monday, September 16, 2019, the first full day of trading after the attack, Brent and West Texas Intermediate (WTI) crude oil prices experienced the largest single day price increase since August 21, 2008 and June 29, 2012, respectively.
(Published: November 6, 2019) Changing nature of non-OPEC supply types may be affecting the crude oil futures market
Changes in the oil investment and production cycle may be affecting trading dynamics for West Texas Intermediate (WTI) and Brent crude oil futures contracts. Many U.S. producers that may have traditionally hedged production years in advance may now only need to hedge using short-dated portions of the futures curve. Many domestic producers have shifted their production portfolios toward tight oil production, which has a short investment and production cycle, and could be reducing their participation in long-dated WTI futures. For example, the ratio of open interest for WTI contract months 13 and longer to current U.S. monthly production has declined since 2013. In contrast, as of October 2019, a similar ratio for Brent crude oil to production outside the Organization of the Petroleum Exporting Countries (OPEC) and the United States increased to its third-highest level, suggesting increased liquidity in long-dated Brent futures (Figure 1). Brent is the relevant crude oil benchmark used among non-OPEC, non-U.S. oil producers. Similar research from the research from the U.S. Commodity Futures Trading Commission (CFTC) published last year suggests the lower open interest among long-dated WTI futures contracts is a result of the changing investment and production cycle for U.S. oil production. In contrast, new upstream projects outside the United States are primarily deepwater projects, which have a long investment and production horizon. These qualities could be contributing to increased participation in the long-dated portion of the Brent future curve.
(Published: December 4, 2019) September was the first month the United States recorded exporting more petroleum than it imported
In September 2019, the United States exported 89,000 barrels per day (b/d) more petroleum (crude oil and petroleum products) than it imported, the first month this happened since monthly records began in 1973 (Figure 1).
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price rose nearly 4 cents from the previous week to $2.57 per gallon on December 30, 31 cents higher than the same time last year. The Gulf Coast price rose nearly 7 cents to $2.28 per gallon, the Midwest price increased nearly 5 cents to $2.45 per gallon, and the East Coast price rose nearly 4 cents to $2.50 per gallon. The Rocky Mountain price fell nearly 3 cents to $2.66 per gallon, and the West Coast price fell nearly 1 cent to $3.22 per gallon.
The U.S. average diesel fuel price rose nearly 3 cents from the previous week to $3.07 per gallon on December 30, 2 cents higher than a year ago. The Gulf Coast price increased nearly 5 cents to $2.81 per gallon, the East Coast price rose more than 4 cents to $3.10 per gallon, the West Coast price increased nearly 3 cents to $3.62 per gallon, and the Midwest price increased 1 cent to $2.98 per gallon. The Rocky Mountain price fell more than 1 cent to $3.11 per gallon.
Propane/propylene inventories decline slightly
U.S. propane/propylene stocks decreased by 0.2 million barrels last week to 88.2 million barrels as of December 27, 2019, 8.1 million barrels (10.1%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest and Rocky Mountain/West Coast inventories decreased by 0.3 million barrels and 0.1 million barrels, respectively. East Coast inventories increased by 0.2 million barrels, and Gulf Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 6.8% of total propane/propylene inventories.
Residential heating oil prices increase, propane prices decrease
As of December 30, 2019, residential heating oil prices averaged almost $3.08 per gallon, more than 2 cents per gallon above last week’s price but more than 2 cents per gallon below last year’s price at this time. Wholesale heating oil prices averaged nearly $2.16 per gallon, almost 3 cents per gallon higher than last week’s price and more than 38 cents per gallon higher than a year ago.
Residential propane prices averaged nearly $2.02 per gallon, less than 1 cent per gallon below last week’s price and almost 42 cents per gallon less than a year ago. Wholesale propane prices averaged more than $0.71 per gallon, almost 6 cents per gallon lower than last week’s price and more than 8 cents per gallon below last year’s price.
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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.
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.
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