One of the most visible impacts of the rise of U.S. unconventional oil production has been the emergence of a discount or differential of U.S. oil prices to international benchmarks over the past few years, thanks to a combination of increasing supply and limited infrastructure. As a result, domestic refiners with access to discount U.S. crude have benefitted from lower input costs while prices for their refined products remained set by the more favorable international market. At the market research firm Morningstar Inc., we believe that the availability of discounted crude oil will continue to result in a feedstock cost advantage for U.S. refiners going forward. In addition to highly complex assets, access to export markets and low operating costs thanks to cheap natural gas, discount crude should support higher structural returns on capital and an improved competitive position for these firms over the next several years.
Over the past five years, a bottleneck emerged as surging production from unconventional plays in the Midcontinent and Canada saturated the Cushing, Okla., market with crude. With no significant capacity from Cushing to the Gulf of Mexico, the WTI differential widened against Brent crude oil to historically high levels of more than $20 per barrel and Midcontinent refiners’ profits soared. The Seaway pipeline reversal, operational this January, is the first step to alleviating this glut. We expect the bottleneck in Cushing to be fully alleviated sometime in 2013-2014 with the looping of Seaway and Gulf Connector.
Once crude begins to flow to the Gulf Coast, we think a different issue emerges. While pipeline capacity to the Gulf may be adequate in a few years, demand on the Gulf Coast may not be. For heavy oil, we see no issue. We estimate by 2017, more than 600,000 barrels per day (bpd) per day of Canadian heavy will make its way to the Gulf Coast, where we estimate there to be total heavy refining capacity of roughly 3.2 million bpd. Light oil, however, is a different issue. If all incremental Texas, Midcontinent and Western Canadian light production moves to the Gulf Coast, we estimate light imports to the Gulf Coast will essentially end in 2014.
By 2016, we forecast total U.S. production to grow to 8.9 million bpd from 6.5 million bpd in 2012. Our analysis indicates that if all the incremental production continues to flow to the Gulf Coast, then another bottleneck would emerge as supply outstrips refinery demand. Therefore, despite pipeline additions, not all incremental light crude production from the Bakken shale and Canada will flow to the Gulf Coast and instead will move to other markets, namely the East and West Coasts. By 2017, we project 1.3 million bpd of light crude will need to move to markets other than PADD 3 (aka the Gulf Coast). As a result, rail will continue to play a material role in transporting domestic production and thus sustain inland discounts due to insufficient pipeline options to coastal end markets.
With the Gulf Coast and Midcontinent markets saturated, Bakken production will also be forced to find new markets. Effectively then, the relative costs of transporting Bakken crude oil to the East Coast and Gulf Coast establishes all domestic crude oil differentials as Light Louisiana Sweet oil (LLS) will trade at some discount to incentivize these movements. The shipping cost along with the cost to rail Bakken to the East Coast, will ultimately set the LLS/Brent differential of $2 to $6 per barrel. Because Bakken volumes on the East Coast would displace waterborne imported crudes, Bakken production would need to sell at a $14 to $17 per barrel discount to Brent to justify the movement of crude. At the same time, Bakken crude must sell at a minimum of a $12 per barrel discount to LLS, based on rail costs into the St. James Terminal in Louisiana. As a result, the minimum $2 per barrel differential between rail to the Gulf Coast and rail to the East Coast sets the floor for the LLS/Brent differential. The cost to ship a barrel of oil to the East Coast of $5 to $6 per barrel sets the upper limit.
The WTI/LLS spread will then settle at approximately the cost of pipeline transportation from Cushing plus any related cost to move the crude to refining centers around the Gulf. As a result, we expect WTI/LLS to settle at the transportation cost of $5 to $6 per barrel and WTI/Brent at $7 to $12 per barrel.
Once light crude is moving to the coasts, displacing all waterborne light imports could happen pretty quickly. We expect to see the gradual backing out of the 1 million bpd of light crude imports from PADD 1 (East Coast) and PADD 5 (West Coast) by 2016. At this point, regional differentials (i.e., California light) to foreign sources will emerge but may only be $1 to $3 per barrel, just enough to be an incentive to refiners to invest in rail transportation of light crude from Canada and the Midcontinent. The end result would be similar to the Gulf Coast, where refiners on the East and West Coasts will likely be processing 100 percent cost-advantaged crude slates, when including discount heavy. The point at which PADDs 1 and 5 are no longer net importers of seaborne crudes will also mark the end of foreign light crude imports into the United States.
We believe that the emergence and sustainability of these light crude discounts in North America translates into a sustainable competitive advantage for domestic refiners. As refining remains a global business and U.S. refiners will continue to capture world prices for refined products through exports, the feedstock cost advantage enjoyed by U.S. refiners places them lower on the global cost curve.
The notion that light crude will become the discount feedstock means substantial investment in heavy upgrading capacity is no longer required to capture crude discounts for North American refiners. Access to cost-advantaged feedstock now includes those refiners that can process crudes that have historically fetched a premium but are now available at a discount due to supply and logistical issues. In this case, some low-complexity refiners may actually have a greater advantage because they are able to capture the discounts without the substantial investment heavy crude processing requires.
Our projected discounts for North American light crude indicate U.S. refiners will realize anywhere from a $2 per barrel advantage for coastal refiners to a $10 per barrel advantage for inland refiners compared to refineries in Europe and Asia. This marks a dramatic shift from the previous five years when U.S. refiners were at a light crude cost disadvantage. That said, we also expect heavy crude should continue to sell at significant discounts to light. Thus, we believe several U.S. refiners enjoy a low-cost feedstock advantage with both light and heavy crudes.
Additionally, the availability of low-cost natural gas provides domestic refiners with an operating cost advantage relative to foreign competitors. This energy cost advantage is likely to be sustainable in our opinion, as we believe the United States will enjoy low natural gas prices relative to most global markets for the foreseeable future. Our long-term price assumption of $5.40 implies that U.S. refiners will continue to enjoy a $1 to $2 per barrel operating cost advantage relative to refiners operating overseas, where the price of natural gas remains oil-linked or much higher due to limited supply.
Finally, North American refiners’ low-cost position ensures that export market access and international price realizations will continue. Without the ability to export, the United States would become a self-contained market and the crude differentials we’ve detailed would no longer confer an advantage. Exports are also becoming increasingly important to keeping the United States and global markets integrated as weakening domestic demand has reduced the need for imports. The ability to export provides refiners with another outlet for production and allows for higher usage rates.
Allen Good is senior equity analyst at Morningstar Inc., which provides stock market analysis and investment research.