Jan 03, 2022
North America will see more crude oil volumes flow from Western Canada and West Texas in 2022, but the crude midstream sector will count only modest, incremental growth with pennies remaining pinched and few big projects sanctioned, according to energy analysts.
With front-month NYMEX WTI hovering above $70/b, the upstream sector is in a healthier place than a year ago, although some COVID-19 resurgence fears remain, but the ongoing energy transition and Wall Street wariness is slowing new investments, and the need for more pipelines and terminals is less dire than it was pre-pandemic when volumes were higher and a wave of infrastructure buildout was wrapping up.
“I think 2022 is going to be a story of modest production growth,” said Matthew Taylor, an energy analyst with Tudor, Pickering, Holt & Co. “Because producers have been limited, that hasn’t translated to the same cash flow uplift for midstream operators. There’s not going to be the same scale of investment there was.”
In January, volumes will begin to pick up on the last, big long-haul Permian crude pipeline to be built for a while, with the completion of the ExxonMobil-led Wink-to-Webster Pipeline system to the Houston area. Including Enterprise Products Partners’ connected Midland-to-ECHO 3 pipeline, the system can move about 1.5 million b/d.
The plan is to start out well under 1 million b/d and then ramp up to more than 1 million b/d by the end of 2022, said AJ O’Donnell, product team director for East Daley Capital.
“You’re going to see more volumes flowing into Houston for sure,” O’Donnell said. “We’ll probably see some attrition on competing pipelines.”
Permian Basin crude production is expected to rise to a new high of nearly 5 million b/d in December after initially taking a big hit during the pandemic. At the same time, Permian crude pipeline capacity is already at more than 6 million b/d after rapid growth in recent years and could soon exceed 7.5 million b/d with Wink-to-Webster, according to S&P Global Platts Analytics.
Any midstream growth in the Permian will focus on connectivity, said Colton Bean, also of Tudor, Pickering, Holt & Co, because any need for long-haul pipelines is a few years away unless some crude pipelines are repurposed to carry NGL or other commodities.
Then the question will be when and if Enterprise receives regulatory approval for its deepwater crude-exporting hub offshore of Houston, the Sea Port Oil Terminal, called SPOT.
“I’m hoping we get that permit on the port in the second quarter,” said Enterprise co-CEO Jim Teague in an interview, referencing the necessary approvals from the US Maritime Administration and the Coast Guard. “We started seeing things moving again, and it’s moving.”
If those approvals come to fruition, SPOT construction could begin in late 2022 or early 2023, taking two or three years for construction and startup.
The race to build crude export hubs offshore of Texas was swiftly halted by the pandemic in 2020, but Enterprise is now hoping to become the first mover and, if all goes as planned, build SPOT without any other Texas competition.
Enterprise has partnered with Enbridge on the project and counts Chevron as the anchor customer. SPOT is proposed to be built about 30 miles offshore of Freeport, which is due south of Houston. The deeper water depths offshore are needed for VLCCs to load up to capacity.
Capline started sending more Canadian crude to the US Gulf Coast starting in December following the line’s reversal from Patoka, Illinois to refineries near St. James, Louisiana.
The reversed Capline Pipeline will move heavy oil sands barrels but will only start out at about 100,000 b/d, and future growth will depend on demand and the construction of new pumping stations along the route.
Within Canada, the October startup of Enbridge’s Line 3 replacement project has expanded capacity from 390,000 b/d to 760,000 b/d and essentially ended the pipeline bottleneck into the US.
With the capacity to now ship 3.2 million b/d across 8,600 miles, Enbridge’s Mainline network, including Line 3, is by far Canada’s largest crude transporter and exporter, moving supplies from the Alberta oil sands to the Ontario and US Midwest refining markets — and farther to the Cushing, Oklahoma storage and pricing hub, and to the US Gulf Coast through additional pipelines.
Heavy Canadian crude pricing has come under pressure over the past several weeks due to increasing Canadian production in Alberta, as well as the prospect of more sour grades in the market, including Shell restarting more production in November from its Mars and Ursa platforms in the US Gulf of Mexico that were impacted by Hurricane Ida.
Other Mainline optimization expansions may depend on the status of Mainline contracting. The Canada Energy Regulator just rejected Enbridge’s longstanding effort to switch the monthly tolling system to long-term contracts, potentially shifting volumes and flows. A redesigned Enbridge proposal will not be resolved until 2023, Enbridge said.
So, next up is the ongoing expansion of the east-to-west Trans Mountain system in Canada that will hike crude capacity from more than 300,000 b/d to 890,000 b/d. The project is slated for completion by the end of 2022, but energy analysts said construction and flooding delays likely will push it back at least until mid-2023.
Sonya Savage, the Alberta energy minister, visited Enbridge’s Seaway terminal while she was in Houston in December for the World Petroleum Congress.
“The Line 3 expansion was critical to Alberta. We need more access to the US Gulf Coast,” Savage said. “The refineries in Houston are looking for a heavier blend, which comes from the oil sands.”