EIA expects Brent crude oil prices to average $73 per barrel in the second half of 2018, then fall to $69 per barrel in 2019
In the July 2018 update of its Short–Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that Brent crude oil prices will average $73 per barrel (b) in the second half of 2018 and $69/b in 2019. EIA expects West Texas Intermediate (WTI) crude oil prices will average $7/b lower than Brent prices in the second half of 2018 and $7/b lower in 2019 (Figure 1).
EIA’s forecast of global liquid fuels balances indicates a looser oil market in the second half of 2018 and through the end of 2019 compared with the tight oil market conditions that prevailed in 2017 and the first half of 2018. Although global petroleum and other liquid fuels inventories declined by an average of 0.5 million barrels per day (b/d) in 2017, EIA expects inventories to be relatively unchanged in 2018 and to increase by 0.6 million b/d in 2019 (Figure 2).
The forecast inventory builds in 2019 are mainly the result of expected liquid fuels production growth in the United States, Brazil, Canada, and Russia. EIA forecasts that these countries will collectively provide 2.2 million b/d out of the 2.4 million b/d of total global supply growth in 2019. Supply growth of this magnitude would outpace EIA’s forecast for global liquid fuels consumption growth of 1.7 million b/d for 2019.
EIA forecasts total U.S. crude oil production to average 10.8 million b/d in 2018, up 1.4 million b/d from 2017, and 11.8 million b/d in 2019. If realized, the forecast level for both years would surpass the previous U.S. record of 9.6 million b/d set in 1970. Crude oil production at these forecast levels would probably make the United States the world’s leading crude oil producer in both years.
Increased production from tight rock formations within the Permian region in Texas and New Mexico accounts for 0.6 million b/d of the expected 1.2 million b/d of crude oil production growth from June 2018 to December 2019. The remaining increase comes from the Bakken, Eagle Ford, other regions in the Lower 48 states, and the Federal Offshore Gulf of Mexico.
However, OECD inventory levels that have fallen below the five-year (2013–17) average and a forecast of low spare capacity among members of the Organization of the Petroleum Exporting Countries (OPEC) create conditions for possible price increases if additional supply disruptions occur or if forecast supply growth does not materialize (Figure 3). EIA expects OPEC surplus production capacity to average 1.7 million b/d in 2018 and to fall to 1.3 million b/d in 2019, a relatively low level compared with the 2008–17 average of 2.3 million b/d. Low OPEC crude oil surplus production capacity can be an indicator of tight oil market conditions. All of OPEC’s currently available surplus production capacity is in Saudi Arabia, Kuwait, the United Arab Emirates, and Qatar.
EIA forecasts OPEC crude oil production to average 31.9 million b/d in 2018, a decrease of 0.6 million b/d compared with the 2017 level. The forecast decline is mainly the result of Venezuela’s rapidly decreasing crude oil production, which fell to less than 1.4 million b/d as of June 2018, a 0.6 million b/d decrease compared with June 2017. OPEC output during the first half of 2018 was also lower as a result of the production caps placed on the group’s producers as agreed upon in the November 2016 OPEC production agreement that aimed to limit OPEC crude oil output to 32.5 million b/d.
OPEC crude oil production averaged 31.9 million b/d in June. Although the OPEC and non-OPEC participants agreed on November 30, 2017, to extend the production cuts through the end of 2018 to reduce global oil inventories, tightening market conditions led the group to relax the production cuts starting in July 2018. EIA expects that OPEC crude oil output will decrease by an average of less than 0.1 million b/d in 2019. This small decline reflects crude oil production increases from some producers that would mostly offset expected combined declines of more than 1.0 million b/d in Iran and Venezuela.
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price increased one cent from the previous week to $2.86 per gallon on July 9, up 56 cents from the same time last year. The Midwest and Gulf Coast prices each increased nearly two cents to $2.78 per gallon and $2.62 per gallon, respectively, the East Coast price increased one cent to $2.78 per gallon, and the West Coast price rose slightly, remaining virtually unchanged at $3.39 per gallon. The Rocky Mountain price decreased marginally, remaining virtually unchanged at $2.96 per gallon.
The U.S. average diesel fuel price increased less than a cent, remaining at $3.24 per gallon on July 9, up 76 cents from a year ago. The Rocky Mountain and East Coast prices each increased over a penny to $3.37 per gallon and $3.24 per gallon, respectively, the Midwest price rose nearly one cent to $3.18 per gallon, and the West Coast and Gulf Coast prices each rose slightly, remaining virtually unchanged at $3.75 per gallon and $3.00 per gallon, respectively.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 2.4 million barrels last week to 63.6 million barrels as of July 6, 2018, 6.4 million barrels (9.2%) lower than the five-year average inventory level for this same time of year. Gulf Coast and Midwest inventories each increased by 1.2 million barrels and Rocky Mountain/West Coast inventories increased by 0.2 million barrels, while East Coast inventories decreased by 0.2 million barrels. Propylene non-fuel-use inventories represented 3.7% of total propane/propylene inventories.
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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
Headline crude prices for the week beginning 3 December 2018 – Brent: US$61/b; WTI: US$52/b
Headlines of the week
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