Skip to Content
Stock Strategist Industry Reports

Would Crude Exports Mean the End for Refiners' Moats?

They would eliminate a key competitive advantage, but aren't necessarily a death knell.

Mentioned: , , , , ,

The Commerce Department's decision to allow two companies to export lightly processed lease condensate raises the question of whether a full repeal of the domestic crude export ban is coming. Unmitigated exports of domestic crude remain unlikely, but the risk is now higher. In the event of repeal, we think refiners would lose the primary source of their cost advantage, as light crude feedstock discounts would be diminished. While refiners' narrow moats rest largely on this cost advantage, its loss does not automatically mean they will lose their Morningstar Economic Moat Ratings. Some refiners would continue to enjoy a feedstock cost advantage, while other competitive advantages could contribute to ensuring excess returns. After analyzing refiners' competitive advantages and returns, we find  HollyFrontier (HFC),  Western Refining (WNR), and  Phillips 66 (PSX) would retain their moats.  Valero (VLO),  Tesoro (TSO), and  Marathon Petroleum (MPC) would not. We find the greatest value in Western and Tesoro. HollyFrontier is undervalued as well, but is more exposed if exports occur.

With Crude Exports, Most Refiners Lose a Key Competitive Advantage
Access to cost-advantaged feedstock was the primary factor behind U.S. refiners earning narrow economic moats. Growing U.S. unconventional light crude production and a ban on crude oil exports resulted in domestic production being discounted to world prices. This discount granted U.S. refiners a cost advantage relative to international peers. With discount light crude, U.S. refiners' crude slates could be composed completely of cost-advantaged feedstock. The earnings uplift from light crude discounts, combined with the relatively low capital intensity of the logistics assets and processing equipment needed to capture those discounts, produced higher sustainable returns compared with the past. Thus, refiners earned narrow moats.

Reversal of the export ban has always been the greatest threat to this advantage. Without the ban on exports, we estimate U.S. light crude discounts would narrow and refiners would lose their structural advantage. We think the decision to allow exports of lease condensate that has been minimally processed increases the risk of an export ban reversal from when we first awarded refiners narrow moats. However, the decision really marks more of a clarification of export rules rather than a wholesale change in policy. As a result, we think a complete export ban reversal remains a low-probability event.

We expect any change in policy would face immense political opposition. The condensate announcement alone prompted several members of Congress to question the Commerce Department about the decision. The department subsequently issued a statement essentially reiterating the existing policy, implying no changes had been made. Reports indicate subsequent applications have been put on hold. The swift response probably portends an even greater one in the likelihood of an official proposal to allow exports. Combined with the midterm elections later this year, further action in 2014 seems unlikely.

That does not mean a reversal of the export ban is inconceivable. In addition, a wide variety of policies exist between the current situation and a complete export ban reversal. Instead of trying to identify each one of those potential policies and the impact on refiners and differentials, however, we just consider a worst-case scenario--a complete and unconditional reversal of the crude export ban--to assess the implications for refiners' moat ratings and valuations.

Light crude differentials would narrow. If the export ban were reversed, some light crude differentials would persist, albeit at narrower levels, while others would dissipate completely. However, a reversal would not result in a complete return to the conditions before 2010, when the U.S. was producing only 5.4 million barrels a day of crude oil and refiners were importing 9.0 mmbd. Instead, domestic production would be capable of meeting PADD 2, 3, and 4 light crude demand, as it does today.

In that case, exports would provide a relief valve to avoid excess inventories and a blowout in differentials. Refiners may even end up processing less light crude than they do now as narrower differentials reduce the incentive to maximize light crude throughput. Regardless, we would still expect a compression in differentials, with the balancing point between domestic and international prices on the Gulf Coast. The result would probably be parity between Light Louisiana Sweet and Brent, with West Texas Intermediate, Permian, and Bakken crude maintaining a discount to compensate for transportation cost to the Gulf Coast.

Refiners outside the Mid-Continent would lose their light crude cost advantage. Narrower differentials eliminate access to cost-advantaged light crude for West and East Coast refineries. Gulf Coast refiners would see access limited, while Mid-Continent refiners would maintain access. With LLS trading at or near parity to Brent, the economics no longer exist to encourage marine shipments of excess Gulf Coast light crude or rail shipments of Bakken crude to the East Coast. California rail also becomes uneconomical. Rail shipments of Bakken crude to Washington refineries would remain viable thanks to equivalent transportation cost to the Gulf Coast of about $10 per barrel. Refineries also would realize additional margins of $3-$5/bbl from improved yields due to the substitution of lower-quality Alaska North Slope with Bakken crude. The margin uplift, along with the option of shipping Canadian heavy, also would maintain the viability of rail to marine facilities in Washington to supply California refineries.

Whether a refiner maintains a light crude advantage depends on the location of its assets. Refineries in the Mid-Continent region where light crude discounts will persist should retain a light crude cost advantage, while those in the Atlantic Basin (U.S. East Coast and Europe) are likely to lose it completely. The outlook for West and Gulf Coast refiners is more complicated than a simple geographic breakdown offers.

HollyFrontier and Western continue to maintain a light crude cost advantage. Western's advantage is also secured by its assets' proximity to the Permian Basin. Phillips 66 would be at risk given its large Atlantic Basin (including European refining) and West Coast exposure. Valero has some Mid-Continent exposure, but is primarily a Gulf Coast refiner. However, projects to move inland discount light crude to the Gulf Coast as well as a primarily western Gulf Coast position (more than 70% of its total Gulf Coast capacity) leave it better positioned. Marathon has a large Mid-Continent presence as well, with half of its coastal position in the western Gulf.

Tesoro is exposed primarily to the West Coast; however, it is already railing Bakken crude to its Washington refinery and could continue to do so in the event of exports. Meanwhile, the company is building a rail-to-marine facility to supply its California refineries with Bakken crude. While the economics would be less attractive in an export scenario, the project would still bestow Tesoro with better margins than it would otherwise realize by processing ANS, thanks to the improved yield.

Complex Assets Become a Critical Advantage Again
For refiners that have lost a light crude advantage, highly complex assets and the ability to produce higher amounts of clean product from cheaper, lower-quality crude become critical advantages again. Without access to light crude differentials, the only other way to reduce feedstock cost will be by processing a discounted heavy barrel. Refiners that already have highly complex assets will be the most advantaged. While refiners could decide to invest in new heavy processing capability, we think it will be harder for them to deliver excess returns, given the higher construction cost (greater invested capital) and potential for narrower light/heavy spreads (lower earnings). Light/heavy spreads are likely to narrow as light crude supply increases, with greater production and heavy crude demand increases from narrower light crude differentials and the recent addition of heavy processing capacity.

Among complex refiners, those in the Mid-Continent are the best positioned thanks to their proximity to an increasing supply of Canadian heavy crude, or WCS. As greater volume of WCS flow from Canada to the Gulf Coast is added, we expect WCS to price off of Maya, less transportation cost, implying a $25/bbl discount to Brent. However, given their proximity to Canada, Mid-Continent complex refiners will enjoy a roughly $6/bbl additional differential compared with Gulf Coast refiners thanks to lower transportation costs.

HollyFrontier holds a clear advantage with highly complex assets located entirely in the Mid-Continent. It also has access and the ability to process black wax crudes in Utah, extending its location and asset advantage. Western's complexity is the lowest of the group, but that's actually an advantage. Western's proximity to the Permian Basin means it generates the greatest returns from maximizing throughput of locally sourced light crude. Highly complex Gulf Coast refiners Valero and Marathon also are well positioned, thanks to the growing availability of heavy crude from Canada that ultimately could price more attractively than waterborne supplies, given its export potential.

Complexity on the West Coast (primarily California) is relatively high for every firm operating in the region. Originally configured to process California heavy crude production, those refiners such as Tesoro are likely to eventually see Canadian heavy crude volumes via rail/marine. The differential, however, will be less attractive than what Mid-Continent refiners will realize. With much lower complexity, Atlantic Basin refiners' troubles are compounded as they have neither access to discount light crude nor the ability to process heavy crude. Once again, with a relatively larger Atlantic Basin footprint and lower West Coast complexity, Phillips 66 is disadvantaged.

U.S. Refiners Continue to Hold an Energy Cost Advantage
The competitive advantage U.S. refiners derive from low domestic natural gas prices merits little discussion, as it will be unaffected by any change in the crude oil export ban. While U.S. and international natural gas prices remained largely in line over the past decade, the emergence of unconventional gas created a disparity. The lower domestic prices offer U.S. refiners an advantage that we think will persist. Our long-term price assumption is $5.40 per thousand cubic feet, leaving U.S. refiners with significantly lower costs than comparable refiners in Europe and Asia, where the price of natural gas remains oil-linked or much higher due to limited supply. Additionally, efforts to extract shale gas in other countries that could result in lower prices have proved fruitless to date.

Loss of Light Crude Advantage Doesn't Mean the End of Exports
If crude exports are permitted, U.S. refiners should be able to maintain their cost competitiveness in the global market and continue to export products. The ability to export and its contribution to refiners' narrow moats could be considered a circular reference. Exports contribute to the narrow moat rating in two ways. First, they allow the U.S. to maintain links to international refined product prices, despite the decline in product imports, ensuring crude differentials don't just result in cheap gasoline. Second, they allow U.S. refiners to maintain high levels of utilization, thus lowering per unit costs, while preventing oversupply in the domestic market as demand declines. In turn, the growth in exports has rested largely on U.S. refiners' cost advantage. The benefit of exports is clear when comparing the U.S. with Europe. Despite product demand decline in both regions, U.S. refiners increased utilization and capacity while Europe refiners realized declines in both.

With differentials likely to narrow in an export scenario, U.S. refiners would lose some of the cost advantage that has led to the increase in exports. However, we do not think that means U.S. export growth would reverse. In fact, we think continued export growth is likely.

First, U.S. refiners will continue to maintain a crude advantage. While U.S. coastal light crude prices such as LLS should trade in line with international benchmarks such as Brent, Gulf Coast refiners can still source inland discounted light crude. Even with exports of light crude, European refiners will not realize a light crude advantage as exported condensates or light crude converge to international pricing, leaving E&Ps to capture narrower differential. In addition, U.S. Gulf Coast refiners will continue to capture heavy crude discounts thanks to their highly complex assets and increasing supply of heavy crude. While Canadian heavy crude may eventually find its way to Europe, U.S. refiners will still process greater amounts at a lower cost due to the proximity to Canada.

Second, U.S. exports to Europe are not a new phenomenon spurred by light crude differentials. Historically, the U.S. and Europe have exchanged excess gasoline and diesel. With the collapse in U.S. and European demand in 2008-09, however, the relationship changed. Though both regions were oversupplied, a cost advantage allowed U.S. refiners to maintain high utilization levels and avoid the severe capacity cuts Europe experienced. Combined with lower demand, the U.S. market for European gasoline imports was largely eliminated.

However, the market for U.S. exports grew. Europe's decline in demand was not uniform. Beginning in 2009, total demand declined steadily each year, reaching approximately 2 mmbd by 2013. However, distillate demand held steady after an initial decline in 2009 of 200 mbd. The refinery closures due to overall demand deterioration, however, resulted in less diesel supply and created an opportunity for U.S. refiners.

We think the European market for U.S. diesel exports will continue to grow. With depressed margins and little change in their competitive position, European refiners' profitability will remain challenged, leading to additional closures. With remaining existing facilities geared for gasoline production, diesel supply will fall. Meanwhile, the divergence in demand between diesel and other products will likely persist as tax policy and greater diesel engine efficiency continue to drive gasoline to diesel switching. In fact, ExxonMobil just authorized a $1 billion investment in its Antwerp refinery premised in part on long-term distillate demand growth in Europe. The result will be a growing European diesel deficit.

In addition, Latin America will remain a viable market for U.S. exports as demand grows and supply shortages continue. Exports to Latin America have increased by 800 mbd in the past four years, more than all other regions combined.

Two factors drove the growth of Latin American exports: first, the combination of U.S. oversupply and refiners' cost advantage; second, a supply shortfall amid robust demand growth. A decline in refining capacity and poorly run assets resulted in insufficient supply issues. Refining capacity in Latin America has fallen about 500 mbd since 2008 while utilization remained poor (below 80%). Consequently, imports were required to meet demand.

We expect Latin America to remain a viable export market for the U.S. as capacity additions fail to meet demand growth. The International Energy Agency expects Latin America to add only 800 mbd of refining capacity by 2019. More capacity could be added beyond then, but if history is any indication, many of these projects will be delayed or not completed. In fact, last year's IEA estimate called for 1.6 mmbd of new capacity by 2019. Additionally, the reliability of the new capacity, if completed, is unlikely to be much better than existing operations, resulting in an inability to meet the current deficit much less the 1.0 mmbd in anticipated demand growth.

The greater risk to U.S. exports is that new refinery construction in other parts of the world, particularly in China and the Middle East, leads to global oversupply. As a result, U.S. refiners could find themselves competing with government-owned refiners that are more concerned with running their facilities at capacity than generating economic profits. However, we remain confident in U.S. refiners' ability to compete, given their aforementioned cost advantages, proximity to end markets, and logistics/export infrastructure. Meanwhile, European refineries are likely to continue to suffer the brunt of any closures as global supply increases. Chinese and Middle East refineries are not immune to delays or cancelations, either. While the IEA reduced new Latin American capacity additions by 800 mbd, it decreased Chinese capacity additions even further, by 1.25 mmbd. Total global downward revisions for 2016-18 totaled 2.4 mmbd, demonstrating the tendency of planned refining capacity additions to be derailed.

Allen Good does not own (actual or beneficial) shares in any of the securities mentioned above. Find out about Morningstar’s editorial policies.