U.S. crude oil production in the Federal Gulf of Mexico (GOM) increased slightly in 2017, reaching 1.65 million b/d, the highest annual level on record. Although briefly hindered by platform outages and pipeline issues in December 2017, oil production in the GOM is expected to continue increasing in 2018 and 2019, based on forecasts in the EIA’s latest Short-Term Energy Outlook (STEO). EIA expects the GOM to account for 16% of total U.S. crude oil production in each year.
Based on STEO’s expected production levels at new fields and existing fields, annual crude oil production in the GOM will increase to an average of 1.7 million b/d in 2018 and 1.8 million b/d in 2019. However, uncertainties in oil markets may still affect long-term planning and operations in the GOM, and the timelines of future projects may change accordingly.
In 2016, producers brought seven new projects and expansions online and ramped up production in 2017, collectively contributing to an average of 126,000 b/d of production in 2017. Another two projects came online in 2017, contributing 10,000 b/d of new production last year. EIA expects these nine projects to ramp up over the next two years. Producers expect four new projects to come online in 2018 and six more in 2019.
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 pull back on future deepwater exploration spending and to restructure or delay drilling rig contracts, causing average monthly rig counts to decline through 2017.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
Recent crude oil price increases 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 discovery in the coming years. Unlike onshore operations, falling rig counts do not affect current production levels, but instead affect the discovery of future projects and fields.
In March 2018, the Bureau of Ocean Energy Management held a lease sale for more than 14,000 Federal Gulf of Mexico blocks, most of which did not receive any bids. Although the results of this auction will not affect GOM production within the Short-Term Energy Outlook forecast horizon (through 2019), the level of interest for leases may have longer-term implications for GOM crude oil production.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
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The week started off ominously. Qatar, a member of OPEC since 1960, quit the organisation. Its reasoning made logical sense – Qatar produces very little crude, so to have a say in a cartel focused on crude was not in its interests, which lie in LNG – but it hinted at deep-seated tensions in OPEC that could undermine Saudi Arabia’s attempts to corral members. Qatar, under a Saudi-led blockade, was allied with Iran – and Saudi Arabia and Iran were not friends, to say the least. This, and other simmering divisions, coloured the picture as OPEC went into its last meeting for the year in Vienna.
Against all odds, OPEC and its NOPEC allies managed to come to an agreement. After a nervy start to the conference – where it looked like no consensus could be reached – OPEC+ announced that they would cut 1.2 mmb/d of crude oil production beginning January. Split between 800,000 b/d from OPEC members and 400,000 b/d from NOPEC, the supply deal contained a little bit of everything. It was sizable enough to placate the market (market analysts had predicted only a 800,000 b/d cut). It was not country-specific (beyond a casual mention by the Saudi Oil Minister that the Kingdom was aiming for a 500,000 b/d cut), a sly way of building in Iran’s natural decline in crude exports from American sanctions into the deal without having individual member commitments. And since the baseline for the output was October production levels, it represents pre-sanction Iranian volumes, which were 3.3 mmb/d according to OPEC – making the mathematics of the deal simpler.
Crude oil markets rallied in response. Brent climbed by 5%, breaking a long losing streak, as the market reacted to the move. But the deal doesn’t so much as solve the problem as it does kick the can further down the road. A review is scheduled for April; coincidentally (or not), American waivers granted to eight countries on the import of Iranian crude expire in May. By April, it should be clear whether those will continue, allowing OPEC+ to monitor the situation and the direction of Washington’s policy against Iran in a new American political environment post-midterm elections. If the waivers continue, then the deal might stick. If they don’t, then OPEC+ has time to react.
There are caveats as well. OPEC members, who are shouldering the bigger part of the burden, said there would be ‘special considerations’ for its members. Libya and Venezuela - both facing challenging production environments – received official exemptions from the new group-level quota. Nigeria, exempted in the last round, did not. Iran claims to have been given an exemption but OPEC says that Iran had agreed to a ‘symbolic cut’ – a situation of splitting hairs over language that ultimately have the same result. But more important will be adherence. The supply deals of the last 18 months have been unusual in the high adherence by OPEC members. Can it happen again this time? Russia – which is rumoured to be targeting a 228,000 b/d cut – has already said that it would take the country ‘months’ to get its production level down to the requested level. There might be similar inertia in other members of OPEC+. Meanwhile, American crude output is surging and there is a risk to OPEC+ that they will be displaced out of their established markets. For now, OPEC remains powerful enough to sway the market. How long it will remain that way?
Infographic: OPEC+ December Supply Deal
Headline crude prices for the week beginning 10 December 2018 – Brent: US$62/b; WTI: US$52/b
Headlines of the week
The Permian is in desperate need of pipelines. That much is true. There is so much shale liquids sloshing underneath the Permian formation in Texas and New Mexico, that even though it has already upended global crude market and turned the USA into the world’s largest crude producer, there is still so much of it trapped inland, unable to make the 800km journey to the Gulf Coast that would take them to the big wider world.
The stakes are high. Even though the US is poised to reach some 12 mmb/d of crude oil production next year – more than half of that coming from shale oil formations – it could be producing a lot more. This has already caused the Brent-WTI spread to widen to a constant US$10/b since mid-2018 – when the Permian’s pipeline bottlenecks first became critical – from an average of US$4/b prior to that. It is even more dramatic in the Permian itself, where crude is selling at a US$10-16/b discount to Houston WTI, with trends pointing to the spread going as wide as US$20/b soon. Estimates suggest that a record 3,722 wells were drilled in the Permian this year but never opened because the oil could not be brought to market. This is part of the reason why the US active rig count hasn’t increased as much as would have been expected when crude prices were trending towards US$80/b – there’s no point in drilling if you can’t sell.
Assistance is on the way. Between now and 2020, estimates suggest that some 2.6 mmb/d of pipeline capacity across several projects will come onstream, with an additional 1 mmb/d in the planning stages. Add this to the existing 3.1 mmb/d of takeaway capacity (and 300,000 b/d of local refining) and Permian shale oil output currently dammed away by a wall of fixed capacity could double in size when freed to make it to market.
And more pipelines keep getting announced. In the last two weeks, Jupiter Energy Group announced a 90-day open season seeking binding commitments for a planned 1 mmb/d, 1050km long Jupiter Pipeline – which could connect the Permian to all three of Texas’ deepwater ports, Houston, Corpus Christi and Brownsville. Plains All American is launching its 500,000 b/d Sunrise Pipeline, connecting the Permian to Cushing, Oklahoma. Wolf Midstream has also launched an open season, seeking interest for its 120,000 b/d Red Wolf Crude Connector branch, connecting to its existing terminal and infrastructure in Colorado City.
Current estimates suggest that Permian output numbered around 3.5 mmb/d in October. At maximum capacity, that’s still about 100,000 b/d of shale oil trapped inland. As planned pipelines come online over the next two years, that trickle could turn into a flood. Consider this. Even at the current maxing out of Permian infrastructure, the US is already on the cusp on 12 mmb/d crude production. By 2021, it could go as high as 15 mmb/d – crude prices, permitting, of course.
As recently reported in the WSJ; “For years, the companies behind the U.S. oil-and-gas boom, including Noble Energy Inc. and Whiting Petroleum Corp. have promised shareholders they have thousands of prospective wells they can drill profitably even at $40 a barrel. Some have even said they can generate returns on investment of 30%. But most shale drillers haven’t made much, if any, money at those prices. From 2012 to 2017, the 30 biggest shale producers lost more than $50 billion. Last year, when oil prices averaged about $50 a barrel, the group as a whole was barely in the black, with profits of about $1.7 billion, or roughly 1.3% of revenue, according to FactSet.”
The immense growth experienced in the Permian has consequences for the entire oil supply chain, from refining balances – shale oil is more suitable for lighter ends like gasoline, but the world is heading for a gasoline glut and is more interested in cracking gasoil for the IMO’s strict marine fuels sulphur levels coming up in 2020 – to geopolitics, by diminishing OPEC’s power and particularly Saudi Arabia’s role as a swing producer. For now, the walls keeping a Permian flood in are still standing. In two years, they won’t, with new pipeline infrastructure in place. And so the oil world has two years to prepare for the coming tsunami, but only if crude prices stay on course.
Recent Announced Permian Pipeline Projects