The oil & gas midstream industry faced multiple challenges in 2022: an increase in demand for American LNG from Europe, growing emissions and ESG pressures, volatile margins and markets, and rising gas and oil production. In 2023, we expect similar challenges and dynamics that will test midstream markets again. Some of these challenges and dynamics that will likely impact midstream in 2023 are summarized below:
New Permian gas takeaway capacity additions will support production growth while oil will suffer from a lack of new additions
With natural gas production reaching highs of over 16 billion cubic feet per day (Bcf/d), three new projects in the Permian will expand existing gas pipeline capacity:
- Kinder Morgan’s Gulf Coast Express Pipeline Expansion will increase compression on the pipeline, boosting capacity by 0.57 Bcf/d to reach 2.55 Bcf/d. The project is expected to become operational in December 2023.
- Another Kinder Morgan project, the Permian Highway Pipeline Expansion, will increase compression and boost capacity by 0.55 Bcf/d to get to 2.65 Bcf/d. The project is scheduled to commence operation in November 2023.
- WhiteWater and MPLX’s Whistler Pipeline capacity expansion will add three new compressor stations to the pipeline, boosting capacity by 0.5 Bcf/d to achieve 2.5 Bcf/d. The project is expected to be operational in September 2023.
On the oil side, crude exports from Corpus Christi account for close to 60% of the total exports, but oil takeaway capacity is reaching its maximum. Today, nearly 2.2 million barrels per day (MMb/d) go from the Permian to Corpus Christi, translating into an 85% utilization rate of takeaway capacity. Without any new expansion projects on the horizon, these pipelines will reach their maximum capacity of 2.5 MMb/d and the growth in supply to Corpus Christi will stall.
Haynesville expands infrastructure in 2023
2.8 Bcf/d of gas transportation capacity will be added in 2023 from three projects: Columbia’s Louisiana Xpress, Enable’s Gulf Run, and DT Midstream’s LEAP Expansion Phase I. The projects include new pipelines, upgrades to existing pipelines, and compressor stations that will help natural gas transportation in Louisiana and Texas. This additional capacity is expected to help meet the growing demand for natural gas in the Gulf Coast region.
Gas takeaway capacity in Appalachia will limit production growth
Gas production in Appalachia has reached 34 Bcf/d, however, takeaway limitations restrict production to 35 Bcf/d during off-peak months. These limitations will become more evident during the fall of 2023, as they will prevent any significant increase in output except for a few periods of high demand when local purchasers require more.
It is expected that no new pipeline capacity will be available in the region shortly, as the only upcoming project, the Mountain Valley Pipeline, remains suspended. Output from the region is nearing its maximum level. For some time, production had been growing rapidly but in 2022, there was an abrupt decrease in growth due to both inadequate pipeline capacity and because operators endeavored to stay away from hitting the capacity wall. Until this capacity issue is resolved, Appalachian gas production will remain limited near its current levels.
NGL production and fractionating capacity will reach new highs
With the current fractionation volumes in the Gulf Coast close to 4 MMb/d, the utilization rate of fractionation facilities will remain between 95 and 100% throughout 2023. The situation might worsen as utilization rates have been over 90% for months, which can lead to unexpected shutdowns and prolonged turnarounds. To maintain the utilization rate closer to 90% or below, investment in fractionation capacity is necessary. Companies must look into expanding their existing plants or building new ones to accommodate the increased supply and demand for natural gas liquids.
Some of the major midstream players are announcing sizeable gas processing investments with companies like Targa Resources, Energy Transfer, Enterprise Products Partners, and MPLX declaring intentions to expand their processing capacity in the Permian Basin by at least 700 MMcf/d by 2024. This new processing capacity will result in more natural gas liquids. These aspects will still be relevant in 2023, albeit limited by the infrastructure needed to take those NGLs to the market (which includes gathering systems, pipelines, and fractionation).
Y-grade storage will be the go-to solution until more fractionation capacity is developed
More storage for Y-grade, or raw NGLs will come online in 2023 as the industry awaits further fractionation capacity. Inventory levels have increased from 5-year lows to over-the-average levels, indicating an increase in storage for NGLs. However, build-up in inventories can cause LPG prices to drop from the current 45% WTI price ratio to lows closer to 30%.
Slow growth in Bakken production will leave excess capacity for years
Oil production in the Bakken remains well below pre-pandemic levels, and the growth rate of oil production has been decreasing. Growth is expected to remain close to 2% in 2023 and reach slightly over 1.2 MMb/d. The additional capacity provided by the Dakota Access Pipeline along with lower production in the region causes a surplus in takeaway capacity, and without the announcement of new projects, 2023 will also remain flat for changes in pipeline infrastructure.
Midstream will continue looking at different technologies to mitigate emissions
In 2023, midstream companies will focus on reducing fugitive methane emissions. Kinder Morgan, Williams, and Enbridge have been trying out different practices for decreasing the number of pipeline blowdowns. Hot tapping, or making new connections, and recompression are two strategies that have become increasingly common of late due to improvements in the industry and the high price of gas. Additionally, companies like OneOK and Marathon have adopted vapor recovery units (VRUs), which can capture roughly 98% of emissions and effectively meet stringent regulations. As these technologies continue to evolve and become more widely adopted, we will observe a considerable decline in methane emissions in the upcoming years.
The Inflation Reduction Act (IRA) of 2022 includes significant funding for energy projects which can see the light in 2023
The IRA is estimated to have an overall cost of $738 billion, including $391 billion for energy and climate change. This budget includes $60 billion for clean energy manufacturing and $30 billion for grants and loans for clean electricity and energy storage. Moreover, there are tax credits and subsidies for pollution reduction and appliance efficiency, investments to abate industrial emissions, and block grants for environmental and climate justice. It is a unique opportunity to finance energy projects that would not be possible otherwise.
While there are incentives for everything from carbon capture through electric vehicles to renewable energy and hydrogen production, there are some penalties. The federal government’s first-ever greenhouse gas (GHG) emission fee is part of the new law’s Methane Emissions Reduction Program (MERP).
Facilities may want to upgrade their equipment and operations to reduce methane emissions to avoid the charge by meeting the required emission level. Because natural gas prices have been so high in recent months, oil and gas producers can either sell the natural gas they capture or keep from leaking. Capture systems can often be economical if such sales offset emissions reductions.
The $850 million allocated to the EPA in the IRA for reducing methane emissions includes providing grants to facilities subject to the methane charge for various purposes, including “improving and deploying industrial equipment and processes.” Furthermore, the cost would be reduced by the $700 million allocated to conventional marginal wells to achieve the same goals because those marginal wells account for a disproportionately large share of emissions.
The IRA’s MERP may further accelerate innovation in developing new technologies, equipment, and tools that will help operators cut methane emissions.
Upcoming pipeline infrastructure will affect the flow of Canadian crude into the U.S.
The Trans Mountain Expansion Project will become operational in late 2023, greatly raising the pipe’s throughput from 300,000 barrels per day to 890,000 barrels per day. This expansion will primarily help bring heavier varieties of crude from the Alberta oil sands to an export facility in British Columbia. While some of the barrels will be exported to the U.S. West Coast, most of them will be exported to Asia, and less oil will go towards Midwest refineries via Enbridge’s Mainline or Keystone pipelines. The shift toward the BC export market will narrow the price gap between Western Canadian Select and West Texas Intermediate crude, and refineries taking Canadian oil will have to deal with higher prices. The effects of the Trans Mountain Expansion on the flow of Canadian crude will likely remain until late 2024, as the market adapts to the new demand for Canadian crude.
Europe will see an increase in gas infrastructure
New infrastructure is coming online to increase supply security and enhance access to non-Russian gas. The Poland-Slovakia Interconnector enters service with a capacity of 201 Bcf per year (Bcf/y) on the Polish side and 166 Bcf/y towards Slovakia.
In Italy, Snam is planning investments to improve gas transportation and supplies from Africa. The company relies on Algeria and Egypt to supply natural gas, and these investments will allow them to replace some of its imports from Russia.
ADI brings deep expertise in midstream oil and gas markets and players. Please contact us to learn more about our research.
Manuel Diaz
