Lack of Heavy Crude Weighing on US Refiners

May 28th, 2019 |

Ahead of IMO 2020, which requires ships globally to use fuels with a sulfur content below 0.5% from 3.5% currently, many thought an opportunity was emerging for US refiners. Complex US refineries could capitalize on an expectation of widening heavy-light crude price differentials and refine the cheaper, more sulfurous crude into IMO-compliant fuels; something simple refineries are less capable of. However, global crude markets can change in an instant, and that’s exactly what happened. US sanctions, infrastructure bottlenecks, and OPEC production cuts have contributed to a shortage of heavy crudes available to refineries around the globe, especially in the US. Today’s discussion will focus on the supply dynamics surrounding this shortage, the likelihood of these issues being resolved in the near term, and whether US refiners have any other options.

Canada is an important source of crude for US refiners. The chart below highlights total heavy and intermediate crude imports to the US by country. Canada exported almost 3.5 MMb/d of heavy and intermediate crudes to the US in 2018. Increased pipeline connectivity, and more recently, dwindling supply from other countries like Venezuela has driven increases in Canadian imports. However, Canadian crude production continues to face pipeline bottlenecks. Environmental opposition to proposed pipeline projects, combined with the current shortage of heated crude railcars, has hamstrung the amount of additional crude that Canada can send to the US.

Numerous pipeline projects have been announced to address this, including Enbridge’s Line 3 replacement project, the Trans Mountain Pipeline expansion, and the Keystone XL Pipeline. However, all of these projects have faced stiff regulatory pushback from state/provincial regulators and environmental groups, causing significant delays to project timelines. Without further delays, Enbridge’s Line 3 project could come online towards the end of 2020; however, BTU forecasts this project alone will not be enough for production to grow significantly over the next five years. Furthermore, these projects only serve a longer-term need for takeaway out of Canada, not the near-term constraint. This year, the Alberta government signed agreements to lease 120 Mb/d in railcar capacity ramping up slowly between July 2019 and mid-2020. However, the recently elected government announced it is working to cancel those agreements. Barring a significant change in the Canadian regulatory environment, it’s unlikely Canadian exports to the US can grow significantly enough to make up for losses from countries like Venezuela.

Since 2010, no country has exported more heavy and intermediate crude to Louisiana and Texas refineries than Venezuela, which BTU Analytics discussed in January. Crude production in Venezuela has declined precipitously since the beginning of 2016, as shown by the chart below. This decline has accelerated since the US placed sanctions on Venezuela’s oil industry in January, leading to a 400 Mb/d decline in crude production in the first four months of 2019. With sanctions in place, US imports of Venezuelan crude have flatlined, and refiners are looking elsewhere to replace those volumes.

Historically, another major source of heavy and intermediate crude for US refiners is out of Saudi Arabia. The likelihood of additional Saudi barrels finding their way to US refiners seems unlikely since Saudi Arabia is leading the way on OPEC’s production cuts, cutting 830 Mb/d of crude from October 2018 levels. While BTU does forecast that Saudi Arabia will increase production in 2H 2019, this increase may have little impact on US imports for multiple reasons. First, Saudi Arabia targeted the US specifically when cutting production and exports, given the transparency behind US  inventory data and its effect on pricing. Second, BTU expects increases in crude from the Kingdom to fill the void left by declining Iranian production driven by US sanctions. With two-thirds of Iran’s 2018 crude exports heading to China, India and Japan, these countries are likely to pose stiff competition for Saudi barrels.

These dynamics have driven the tightening in heavy to light crude differentials at the US Gulf Coast beginning in late 2018, as shown by the chart below. While pricing has widened recently between US Gulf light and heavy grades, differentials could tighten again based on where incremental heavy and intermediate barrels from Saudi Arabia end up in 2H 2019, or if the Kingdom increases production at all. Refiners have been sourcing additional crude from Iraq and Colombia recently. However, a significant change in trade flows from Iraq and increased production from Colombia are unlikely.

The EIA is forecasting that pricing for IMO 2020-compliant fuels will increase next year, but tight light-heavy crude differentials could dampen those benefits for refiners. And while refiners generally have some optionality in crude slates, US refiners as a whole are already running the lightest slate of crude on record going back to 1985. As a barrage of cheap, light domestic crude production flooded the US market since the shale revolution, many refineries have already invested the capital to maximize running light crude.  Therefore, accessing significantly more capacity to swap heavy for light barrels is expensive and economically challenged for many US refiners.

Without a significant shift in trade flows from Saudi Arabia or changes to the Canadian regulatory environment, the shortage of heavy and intermediate crudes is likely to persist in the near term leaving US heavy refiners to bear the burden. How does BTU forecast Saudi Arabian production for the rest of 2019 and beyond, and how could this impact crude prices? For more information, request a copy of the Oil Market Outlook today.

Author: Matt Hagerty

Matt Hagerty is an Energy Analyst at BTU Analytics, leading the publication of BTU’s Oil Market Outlook, where he forecasts crude pricing and global crude balances, as well as the E&P Positioning Report, where he models well-level economics and undrilled inventory across 11 major shale plays. He also is or was previously responsible for overseeing oil and gas production forecasts out of Texas, the Williston Basin, Rockies and Louisiana. Prior to joining BTU, he was an energy research associate at Bloomberg Intelligence. Matt holds a B.S. in Finance from Tulane University.