Founded in 1944 in El Dorado, Arkansas, Murphy Oil isn’t quite an international major but the American oil company managed to boost itself up the ranks of the world’s independent oil companies to become a successful player. Part of this has comes from Murphy Oil’s decision to branch out overseas in the 1990s, venturing east to strike oil and gas in the states of Sarawak and Sabah in 1999.
Last week, Murphy Oil announced that it would be selling its stakes in both its Malaysian subsidiaries – covering five upstream projects including Sabah K, SK309 & SK311, Sabah H, SK314A and SK405B – to Thailand’s PTTEP for US$2.13 billion. Effectively ending the era for Murphy Oil in Malaysia. It is the largest M&A deal in Southeast Asian upstream in over five years, and could be an indication of an upcoming trend for the region’s players in general.
For Murphy Oil, the sale is a philosophical change. Of the company’s proven reserves of 816 million boe in 2018, some 16% - or 129 million boe – are in Malaysia. Murphy Oil’s Malaysian fields produced over 48,000 boe/d over the same period, which is a large volume to lose particularly for one that is publicly-traded in the NYSE. But it makes sense. Malaysia was Murphy’s only bright spot internationally. Its forays into other developing markets like Australia, Brunei, Vietnam, Namibia, Equatorial Guinea and Spain have not been as successful. On its home turf, the shale revolution is re-invigorating and re-inventing American upstream. High-yielding and low-cost, it has presented Murphy Oil with a question – why spend money on riskier overseas projects when there is so much potential available at home? This PTTEP deal is Murphy’s answer; and the money raised will be used to pay down debt, buy back shares and (crucially) fund new deals and acquisitions in the US. This won’t just be focused on shale – although Eagle Ford has been named as a focus area – but also more traditional assets in the Gulf of Mexico.
Market chatter suggests that Murphy Oil will be selling off most of its non-Western Hemisphere assets. So while Murphy Oil prepares to go back home, the sale kicks off what could be a major year of M&A in Southeast Asia. When rumours of the sale emerged last year, it was Repsol that was thought to be the preferred buyer – fresh from its massive gas find in Indonesia. Together with Eni, Repsol has been one of the more aggressive European players expanding in Asia – galvanised by declining assets elsewhere. Meanwhile, players who have the capability to swing into the shale oil patch – Chevron, for example – are slowly refocusing there, possibly to the risk of putting eggs into a single basket. And regional players – like PTTEP – are looking to make inroads. That PTTEP won the sale is interesting. Like many Asian state-linked oil firms, PTTEP suffers from a maturing portfolio and needs to find new fields to plumb. Its Thai fields are declining and new discoveries aren’t keeping pace to keep the numbers up. Having ventured into Australia, Indonesia, Myanmar and even Africa, PTTEP’s relevance as an upstream player depends on making strategic acquisitions like this. And Murphy Oil’s Malaysian assets are valuable. Murphy Oil will receive up to US$100 million as a bonus payout if certain exploration projects are completed and sold results before October 2020. Also, Murphy Oil had a close relationship with Petronas; with PTTEP, there may be more opportunities for both state firms to collaborate on other regional assets.
This recalibration will continue. As players capable to focusing on shale divest out of Southeast Asia, there will be plenty other eager players to take their place. Attractive assets always draw interest, whether it is in the Permian Basin or in the South China Sea.
Murphy Oil Malaysian Assets and Projects:
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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