It has been a year of surprising elections so far. A historic change in Malaysia. Imran Khan in power in Pakistan. And Mexico veering left by electing Andres Manuel Lopez Obrador – also known as AMLO – embracing nationalistic and socialist policies after Peña Nieto embarked on a liberalisation drive that busted open long-held monopolies.
The election presages possible changes in Mexico’s energy sector, threatening to undo the gains triggered when former President Nieto broke state-owned Pemex’s dominance in both upstream and downstream. The result? Foreign investment soared. The retail sector was the first to see major change – Shell, BP and even Glencore have set up fuel networks. Pipelines were next, with American firms rushing to connect the US Gulf Coast to energy-hungry Mexico. Net imports of fuel are rising, but that is a symptom of an ageing and ailing refining industry. In upstream, Mexico has offered up blocks for auction to private players over the past two years, attracting plenty of interest from firms like ExxonMobil and Chevron, especially in the deepwater Gulf.
That may change now. AMLO is more protectionist, and indications of his policies when he assumed Presidentship on 1 December 2018 show that he wants to reinstate (some) power to Pemex. He originally vehemently opposed the breakup of the state’s stranglehold on the energy sector, and though he has moderated his position, he still wants the state to play a bigger role than envisaged under Nieto. AMLO reportedly wants to suspend all oil auctions for two years, possibly up to six years, after two successful auctions with high foreign participation. He also wants to review all 107 E&P contacts already awarded, weaken the new technocratic approach at the national regulator, make Pemex the sole marketer of all fuels (included volumes privately-produced) and allow Pemex to choose its upstream private-sector partners, rather than be paired up with the highest bidders. In short, AMLO wants to turn Pemex from Pertamina to Petronas.
It could go even further. AMLO also wants to roll back the new oil and gas laws, a change that would go beyond adjusting current legislation to creating a new law. That is a lot tougher, as it requires a change to the constitution, which is difficult given the fragile state of politics in Mexico. Raising local content rules is also in the works. This is a move that always rankles foreign investors, taking Pemex in the direction of Petrobras – once lauded, but beset with graft scandals brought about by corruption practised between domestic players; but unlike Petrobras, Pemex does not have the lure of vast pre-salt deposits.
This could be a disaster. The supermajors and majors began re-entering Mexico after a long absence in 2017 because Peña Nieto created an environment conducive for them. Rolling back those changes could drive them away, and their much-needed capital. Pemex, like Pertamina, is in no position to fund AMLO’s ambitious plans for Mexican energy. It needs foreign expertise, and crucially, foreign money. To take Pemex towards the standard of a Petronas or Saudi Aramco is a great and laudable ambition; AMLO’s policies are not the way to achieve that.
AMLO’s targets for Mexican energy
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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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