“He Ain’t Heavy, He’s My Feedstock” – The Changing U.S. Gulf Coast Heavy Crude Market

By John Mayes and John Auers

Driven by decades of massive investments in coking and hydrotreating expansions, the U.S. Gulf Coast consumes a large percentage of the global heavy crude output.  The investment was driven in turn by the rapid growth in production of this type of crude in the Latin American nations of Mexico and Venezuela.  This growth began in the 1980s and accelerated during the 1990s, with most of this crude heading to refineries on the U.S. Gulf Coast.   Over the last twenty years, both production of and imports from Mexico and Venezuela have in turn slowed, peaked and fallen significantly from each of those countries.  In fact, the proportion of heavy crude imports from those two countries has declined from 85% of the USGC total in 2007 to 56% in 2017.  While Mexican imports have stabilized over the last three years, Venezuelan declines have only accelerated as the political and economic situation in that country continues to deteriorate rapidly.  With the appetite for heavy crude on the USGC remaining strong and additional declines in Venezuela expected, this is creating opportunities for other countries to increase their exports to the U.S.  These dynamics, along with other external factors (such as the impending IMO bunker regulations in 2020), will create a continually evolving heavy crude supply picture for USGC refiners.

The Road is Long, With Many a Winding Turn” – Background

Crude production in Venezuela (which is primarily heavy) peaked in 1997 at 3.3 million BPD (Figure 1), and while it fell below 3 million BPD in the early 2000s, it remained relatively stable (per reported numbers) at about 2.5 million BPD through 2015. By 2017 however, output fell to average only about 2 million BPD, while current estimates indicate a production level below 1.4 million BPD.  As recently as 2015, Venezuela supplied 38% of the USGC heavy crude requirements.  In the first quarter of the 2018 however, Venezuela only comprised 22% of the region’s heavy imports and was eclipsed by the recently stabilized level of heavy imports from Mexico.  Despite significant pipeline limitations from Canada, it was also only marginally above volumes from that country.  By volume, heavy crude imports from Venezuela to the USGC have declined by 300 MBPD since the recent drop in production began in 2015 and by 700 MBPD from peak levels during the early 2000s.

When Venezuelan and Mexican heavy imports first began to decline in the middle of the last decade, growing production of heavy crude from Colombia and Brazil stepped up to make up for those shortfalls.  More recently, imports from those Latin American countries has also leveled off.  Taking over the slack has been rapidly growing volumes from the Middle East, especially Iraq, and also from Canada.  Heavy crude imports into the USGC from Iraq have jumped from an average of only 14 MBPD in 2015 to over 200 MBPD in the first quarter of 2018 (Figure 2).  The major driving force for this development has been the beginning of the segregation of heavy production into a new Basrah Heavy grade, which started in June 2015 and much of the future incremental output from Iraq is expected fall into this category.  Canadian volumes of heavy crude making it to the USGC have increased by about 100 MBPD, despite the aforementioned cross border pipeline limitations.

 

 “So On We Go” – Near-Term Supply and Demand Changes

The short-term prognosis for heavy crude supply to the USGC appears very similar to recent history.  Venezuelan crude production is expected to continue to decline even if regime change were to occur quickly.  The longer the current turmoil continues however, the greater the decline.  The ultimate return of foreign capital and expertise will not occur quickly under any circumstance and the rebuilding of the Venezuelan oil industry and a return to production growth could take up to a decade or more.

The other Western Hemisphere heavy crude sources also have supply issues for the near term.  In the first quarter of 2018, Mexico temporarily re-emerged as the leading supplier of heavy crude to the USGC, but future production prospects do not look encouraging.  Oil production, including NGLs, peaked in 2004 at 3.8 million BPD but has since declined to only 2.1 million BPD.  Heavy oil production has seen a modest rebound recently (Figure 3), which has allowed exports to the USGC to stabilize, but we expect this to be only temporary.    The newly elected President of Mexico, Mr. Lopez Obrador, has made bold predictions of a rapid increase in production of as much as 600 MBPD; however, those appear to be mere wishful thinking and we expect his moves to restrain or even stop the movement to reform Pemex and open Mexican petroleum markets to foreign investments are likely to further decrease production levels.

Oil production in Colombia has also peaked.  Output exceeded 1 million BPD in 2015 but fell to 875 MBPD in 2017, even as imports to the USGC have remained relatively constant.  Continued modest production declines are expected in the near future.  Over 70% of Colombian crude is heavy.

Unlike Venezuela, the decline in Brazilian heavy crude imports is not the result of declining production.  Even with the backdrop of considerable political turmoil, oil output has been steadily increasing in recent years (Figure 4) and additional gains are expected in the near term.  The shift away from heavy crude exports into the USGC is more economically driven than political.

Production growth is also not the issue with Canada, which is also expected to increase its heavy crude output.  The Canadian Association of Petroleum Producers (CAPP) estimates that heavy crude production will grow from slightly under 2.9 million BPD in 2017 to 3.3 million BPD in 2020 and to 3.6 million BPD in 2025 (Figure 5).  After the full ramp up of the Fort Hills development by the end of this year, the bulk of the future gains are through a series of smaller projects.

While pipeline exit capacity may become a limiting factor in raising production rates in Alberta, the government’s recent action to purchase the Trans Mountain pipeline from Kinder Morgan indicates a substantive commitment to removing obstacles to future growth.  While rising Canadian production represents a credible alternative to replace declining output from Venezuela and Mexico, an increase in pipeline capacity to the U.S. is critical.  The potential to expand the Trans Mountain line also opens the opportunity for Canada to export to Chinese and other Asian refineries and may ultimately reduce volumes flowing to the USGC.

As noted earlier, the country with the largest growth of heavy crude exports to the USGC since 2015 has been Iraq.  Production growth has been impressive in recent years (Figure 6), rising from only 1.3 million BPD in 2003 to nearly 4.5 million BPD in 2017.  While the country has not hit its recent growth targets, the increase have been dramatic nonetheless.  Officially, the Iraqi government has plans to further increase output to 6.5 million by 2022.  Many of the current limitations have less to do with production capabilities but are more related to export capacities resulting from pipeline limitations and bottlenecks at the port of Basrah.

That Leads Us to Who Knows Where” – IMO Impacts

The IMO mandated reduction in bunker fuel sulfur levels, set to begin in January 2020, will have a variety of significant impacts on petroleum markets.  Because of the expected diversions of 1-2 million BPD of distillates into the bunker pool, their prices are expected to spike higher, while the comparable volume of high sulfur fuel oil which is backed out of the pool will force HSFO prices lower.  The reduction in HSFO prices is expected to be so severe that some of the volume will become a refinery feedstock in the form of coker feed.  This diversion of HSFO to coker feed, along with the decrease in value of high sulfur residual barrels will result in lower prices for heavy sour crudes.

While this dynamic is progressing, a similar trend is causing light crude prices to rise higher.  The natural instinct of fuel oil refiners which are unable to produce a 0.5% sulfur compliant fuel is to reduce their noncompliant fuel oil yields by lightening and sweetening their crude slates.  Because there is a limit to the growth of light crude production, the higher demand will result in higher light crude prices.

The combination of these two trends is expected to widen the light/heavy crude differential in 2020.  Not only will this incentivize heavy crude/resid processing on the USGC in the near term, it will also lead to the expansion of existing coker capacity or even new units (such as the project Marathon has publicly announced it is considering at its Garyville refinery).  It will also lead to a shift in crude trade patterns, the most prominent of which we feel is an incentive to move more Middle East high sulfur medium grades to USGC coking refineries as the economics of processing those barrels in less complex refineries in Europe and Asia that produce high sulfur residuals declines significantly.

This subject is discussed in greater detail in the release of our 2018 Crude and Refined Products Outlook (C&RPO) later this week.  These developments play an important role in our overall analysis of global and regional crude supply, demand and pricing, and are accounted for in the forecasts we make for each of these, which are included in the C&RPO.  For more information on this report or on any of our other analyses or consulting capabilities, please send us an email or give us a call.