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
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U.S. crude oil production in the U.S. Federal Gulf of Mexico (GOM) averaged 1.8 million barrels per day (b/d) in 2018, setting a new annual record. The U.S. Energy Information Administration (EIA) expects oil production in the GOM to set new production records in 2019 and in 2020, even after accounting for shut-ins related to Hurricane Barry in July 2019 and including forecasted adjustments for hurricane-related shut-ins for the remainder of 2019 and for 2020.
Based on EIA’s latest Short-Term Energy Outlook’s (STEO) expected production levels at new and existing fields, annual crude oil production in the GOM will increase to an average of 1.9 million b/d in 2019 and 2.0 million b/d in 2020. However, even with this level of growth, projected GOM crude oil production will account for a smaller share of the U.S. total. EIA expects the GOM to account for 15% of total U.S. crude oil production in 2019 and in 2020, compared with 23% of total U.S. crude oil production in 2011, as onshore production growth continues to outpace offshore production growth.
In 2019, crude oil production in the GOM fell from 1.9 million b/d in June to 1.6 million b/d in July because some production platforms were evacuated in anticipation of Hurricane Barry. This disruption was resolved relatively quickly, and no disruptions caused by Hurricane Barry remain. Although final data are not yet available, EIA estimates GOM crude oil production reached 2.0 million b/d in August 2019.
Producers expect eight new projects to come online in 2019 and four more in 2020. EIA expects these projects to contribute about 44,000 b/d in 2019 and about 190,000 b/d in 2020 as projects ramp up production. Uncertainties in oil markets affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.
Source: Rystad Energy
Because of the amount of time needed to discover and develop large offshore projects, oil production in the GOM is less sensitive to short-term oil price movements than onshore production in the Lower 48 states. In 2015 and early 2016, decreasing profit margins and reduced expectations for a quick oil price recovery prompted many GOM operators to reconsider future exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2018.
Crude oil price increases in 2017 and 2018 relative to lows in 2015 and 2016 have not yet had a significant effect on operations in the GOM, but they have the potential to contribute to increasing rig counts and field discoveries in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead they affect the discovery of future fields and the start-up of new projects.
Source: U.S. Energy Information Administration, Monthly Refinery Report
The API gravity of crude oil input to U.S. refineries has generally increased, or gotten lighter, since 2011 because of changes in domestic production and imports. Regionally, refinery crude slates—or the mix of crude oil grades that a refinery is processing—have become lighter in the East Coast, Gulf Coast, and West Coast regions, and they have become slightly heavier in the Midwest and Rocky Mountain regions.
API gravity is measured as the inverse of the density of a petroleum liquid relative to water. The higher the API gravity, the lower the density of the petroleum liquid, so light oils have high API gravities. Crude oil with an API gravity greater than 38 degrees is generally considered light crude oil; crude oil with an API gravity of 22 degrees or below is considered heavy crude oil.
The crude slate processed in refineries situated along the Gulf Coast—the region with the most refining capacity in the United States—has had the largest increase in API gravity, increasing from an average of 30.0 degrees in 2011 to an average of 32.6 degrees in 2018. The West Coast had the heaviest crude slate in 2018 at 28.2 degrees, and the East Coast had the lightest of the three regions at 34.8 degrees.
Production of increasingly lighter crude oil in the United States has contributed to the overall lightening of the crude oil slate for U.S. refiners. The fastest-growing category of domestic production has been crude oil with an API gravity greater than 40 degrees, according to data in the U.S. Energy Information Administration’s (EIA) Monthly Crude Oil and Natural Gas Production Report.
Since 2015, when EIA began collecting crude oil production data by API gravity, light crude oil production in the Lower 48 states has grown from an annual average of 4.6 million barrels per day (b/d) to 6.4 million b/d in the first seven months of 2019.
Source: U.S. Energy Information Administration, Monthly Crude Oil and Natural Gas Production Report
When setting crude oil slates, refiners consider logistical constraints and the cost of transportation, as well as their unique refinery configuration. For example, nearly all (more than 99% in 2018) crude oil imports to the Midwest and the Rocky Mountain regions come from Canada because of geographic proximity and existing pipeline and rail infrastructure between these regions.
Crude oil imports from Canada, which consist of mostly heavy crude oil, have increased by 67% since 2011 because of increased Canadian production. Crude oil imports from Canada have accounted for a greater share of refinery inputs in the Midwest and Rocky Mountain regions, leading to heavier refinery crude slates in these regions.
By comparison, crude oil production in Texas tends to be lighter: Texas accounted for half of crude oil production above 40 degrees API in the United States in 2018. The share of domestic crude oil in the Gulf Coast refinery crude oil slate increased from 36% in 2011 to 70% in 2018. As a result, the change in the average API gravity of crude oil processed in refineries in the Gulf Coast region was the largest increase among all regions in the United States during that period.
East Coast refineries have three ways to receive crude oil shipments, depending on which are more economical: by rail from the Midwest, by coastwise-compliant (Jones Act) tankers from the Gulf Coast, or by importing. From 2011 to 2018, the share of imported crude oil in the East Coast region decreased from 95% to 81% as the share of domestic crude oil inputs increased. Conversely, the share of imported crude oil at West Coast refineries increased from 46% in 2011 to 51% in 2018.
Headline crude prices for the week beginning 7 October 2019 – Brent: US$58/b; WTI: US$52/b
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