Now that the dust on the Chevron-Occidental-Anadarko acquisition battle has settled – with Occidental emerging victorious after help from Warren Buffet – the question on industry lips is: what, or who, is next? Emerging as a collection of bootstrapped pioneers and ambitious independents, the emerging profile of the onshore basin has attracted the attention of supermajors in recent years. While the likes of Chevron and ExxonMobil have acquired some acreage organically, the choicest parts and assets are in the hands of smaller players. When Chevron first announced its deal for Anadarko, it was thought of that that would kick off an acquisition bonanza. That might still happen.
Generating a lot of talk is Endeavor Energy Resources. With a huge 350,000 acres position in the Permian’s Midland Basin, Endeavor is the largest private company in the area. Chatter in the market suggest that Shell might make an official move for Endeavor soon for US$8 billion, and it’s easy to see why. Much of Endeavor’s drilling rights is mostly undeveloped; while that means that Shell can’t hit the ground running with an acquisition, it has long-term attraction considering the high depletion rate observed in Permian fields. Shell itself is reportedly on the prowl for expansion in the Permian, having largely finished its asset rationalisation programme after the US$61 billion takeover of the BG Group and the fact that it majorly lags behind rivals ExxonMobil and Chevron in the space.
Next is Diamondback Energy, a Permian pure-play firm that has valuable assets in the Midland Basin as well as the prized (and prolific) Delaware Basin. Diamondback’s asset map covers 200,000 acres – including several tracts that are contiguous with ExxonMobil and Chevron’s current acreage in the Delaware. Also worth considering is Concho Resources, another Permian pure-play with large acreages scattered across the Midland and Delaware Basins. The largest of these are adjacent to Occidental’s own areas, so it would not be a surprise if Occidental gears up appetite for another buy.
But right on top of the list of Pioneer Natural Resources. Although its CEO has recently stated that Pioneer is not for sale, things might change with the right price. With Pioneer having sold off the last of its remaining assets in Eagle Ford shale, Pioneer is now a Permian pure-play, it has over 785,000 acres in the Midland Basin. Although less prolific than the Delaware, the Midland Basin is still attractive and Pioneer’s position is particularly concentrated and contiguous. Brushing up against Pioneer’s acreage is ExxonMobil and Chevron’s own boundaries, and its new status as a Permian pure-play makes Pioneer particularly attractive for integration compared to the complex and global portfolio of Anadarko. Of course, this doesn’t preclude the scenario where Pioneer itself goes on a shopping spree. With cash on hand at US$1.4 billion and net profits for 2018 at US$1 billion, it might have to borrow to buy, but the long-term dividends might be worth it.
Other names popping up on potential acquisition lists include Parsley Energy, Centennial Resource Development, EOG Resources, Noble Energy and Apache – the latter three having expansion ambitions of their own. The list of potential suitors for these jewels is long. Besides the ambitious duo of ExxonMobil and Chevron, as well as the new interest from Shell, there is also BP (which bought BHP’s Permian assets last year), ConocoPhillips and US independents Devon Energy, Marathon Oil and Encana. Interest could also come from further afield, with chatter suggesting interest from Chinese, Malaysian and even Thai players. In fact, the only major players that have largely ruled out running to the Permian are France’s Total and Italy’s Eni, both of which are concentrating on the high potential of their African assets. The race for the Permian is on and in three years, the corporate landscape there will look very much different
Top Permian basin acquisition targets:
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Recent headlines on the oil industry have focused squarely on the upstream side: the amount of crude oil that is being produced and the resulting effect on oil prices, against a backdrop of the Covid-19 pandemic. But that is just one part of the supply chain. To be sold as final products, crude oil needs to be refined into its constituent fuels, each of which is facing its own crisis because of the overall demand destruction caused by the virus. And once the dust settles, the global refining industry will look very different.
Because even before the pandemic broke out, there was a surplus of refining capacity worldwide. According to the BP Statistical Review of World Energy 2019, global oil demand was some 99.85 mmb/d. However, this consumption figure includes substitute fuels – ethanol blended into US gasoline and biodiesel in Europe and parts of Asia – as well as chemical additives added on to fuels. While by no means an exact science, extrapolating oil demand to exclude this results in a global oil demand figure of some 95.44 mmb/d. In comparison, global refining capacity was just over 100 mmb/d. This overcapacity is intentional; since most refineries do not run at 100% utilisation all the time and many will shut down for scheduled maintenance periodically, global refining utilisation rates stand at about 85%.
Based on this, even accounting for differences in definitions and calculations, global oil demand and global oil refining supply is relatively evenly matched. However, demand is a fluid beast, while refineries are static. With the Covid-19 pandemic entering into its sixth month, the impact on fuels demand has been dramatic. Estimates suggest that global oil demand fell by as much as 20 mmb/d at its peak. In the early days of the crisis, refiners responded by slashing the production of jet fuel towards gasoline and diesel, as international air travel was one of the first victims of the virus. As national and sub-national lockdowns were introduced, demand destruction extended to transport fuels (gasoline, diesel, fuel oil), petrochemicals (naphtha, LPG) and power generation (gasoil, fuel oil). Just as shutting down an oil rig can take weeks to complete, shutting down an entire oil refinery can take a similar timeframe – while still producing fuels that there is no demand for.
Refineries responded by slashing utilisation rates, and prioritising certain fuel types. In China, state oil refiners moved from running their sites at 90% to 40-50% at the peak of the Chinese outbreak; similar moves were made by key refiners in South Korea and Japan. With the lockdowns easing across most of Asia, refining runs have now increased, stimulating demand for crude oil. In Europe, where the virus hit hard and fast, refinery utilisation rates dropped as low as 10% in some cases, with some countries (Portugal, Italy) halting refining activities altogether. In the USA, now the hardest-hit country in the world, several refineries have been shuttered, with no timeline on if and when production will resume. But with lockdowns easing, and the summer driving season up ahead, refinery production is gradually increasing.
But even if the end of the Covid-19 crisis is near, it still doesn’t change the fundamental issue facing the refining industry – there is still too much capacity. The supply/demand balance shows that most regions are quite even in terms of consumption and refining capacity, with the exception of overcapacity in Europe and the former Soviet Union bloc. The regional balances do hide some interesting stories; Chinese refining capacity exceeds its consumption by over 2 mmb/d, and with the addition of 3 new mega-refineries in 2019, that gap increases even further. The only reason why the balance in Asia looks relatively even is because of oil demand ‘sinks’ such as Indonesia, Vietnam and Pakistan. Even in the US, the wealth of refining capacity on the Gulf Coast makes smaller refineries on the East and West coasts increasingly redundant.
Given this, the aftermath of the Covid-19 crisis will be the inevitable hastening of the current trend in the refining industry, the closure of small, simpler refineries in favour of large, complex and more modern refineries. On the chopping block will be many of the sub-50 kb/d refineries in Europe; because why run a loss-making refinery when the product can be imported for cheaper, even accounting for shipping costs from the Middle East or Asia? Smaller US refineries are at risk as well, along with legacy sites in the Middle East and Russia. Based on current trends, Europe alone could lose some 2 mmb/d of refining capacity by 2025. Rising oil prices and improvements in refining margins could ensure the continued survival of some vulnerable refineries, but that will only be a temporary measure. The trend is clear; out with the small, in with the big. Covid-19 will only amplify that. It may be a painful process, but in the grand scheme of things, it is also a necessary one.
Infographic: Global oil consumption and refining capacity (BP Statistical Review of World Energy 2019)
|Region||Consumption (mmb/d)*||Refining Capacity (mmb/d)|
*Extrapolated to exclude additives and substitute fuels (ethanol, biodiesel)
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Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.
The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.
Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.
Source: U.S. Energy Information Administration
First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.
Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.
Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.
Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.
Principal contributor: Jesse Barnett