Prior to 2011, West Texas Intermediate, Brent and Louisiana Light Sweet crudes traded closely together. Producers would generally get the same price whether they delivered crude to Cushing, the Gulf or the East and West coasts.

As U.S. production has ramped up during the past few years, however, these relation- ships have changed (see Figure 1). Basis risk now abounds in crude markets. Understanding the fundamentals behind crude basis and having an appropriately designed hedging strategy are priorities for U.S. producers. This article examines changing crude flows to identify the drivers of basis risk; just as importantly, it highlights the growing risk that U.S. crude prices could move significantly lower.

North America is seeing unprecedented growth in crude production from tight oil and oil sand formations. The Energy Information Administration (EIA) expects that, in 2014, the U.S. will produce an incremental 1 million barrels per day (MMbbl/d) of crude from shale basins (primarily the Bakken, Eagle Ford and Permian) and will import an incremental 0.5 MMbbl/d from Canada. Combined, that’s an additional 1.5 MMbbl/d of North American crude flowing through U.S. refineries in 2014 that will displace foreign crude. And 2015 is likely to show strong year-on-year production growth as well (see Figure 2).

Supply shifts from Cushing to the Gulf

A chart of LLS vs. Brent and LLS vs. WTI spot prices illustrates how production increases have affected crude movements in the U.S. (see Figure 3). Prior to 2011, when the U.S. imported significant amounts of Brent-priced imports at the Gulf, both LLS and WTI traded at slight premiums to Brent.

Then, new shale production in the Bakken and Permian caused crude to pile up in Cushing and created concerns that oil could become stranded. This resulted in WTI pricing at a sizable discount to LLS for most of 2011 through 2013. In response, many large pipeline projects were undertaken to bring crude supplies from Oklahoma to the Gulf Coast. In the second half of 2013, these projects reduced inventories at Cushing and narrowed the LLS-WTI spread dramatically. Today, forward LLS prices trade about $4 per barrel above WTI, roughly in line with the transportation fees needed to move crude from Cushing to the Gulf.

Also, LLS has recently begun to trade at a discount to Brent after years of trading at a slight premium. Fundamentally, this reflects U.S. light-sweet tight oil backing out Brent-priced imports on the Gulf Coast. U.S. tight oil production, once thought to be gridlocked at Cushing, is now flowing to the Gulf unimpeded.

Figure 1: U.S. crude benchmark prices have shown meaningful divergences from world prices since 2011.

Figure 2: U.S. tight oil production is expected to continue growing at a brisk pace in 2014 and 2015.

Figure 3: Market prices reflect that the supply buildup at Cushing has been relieved and oil is making its way to the Gulf Coast.

Figure 4: Light-sweet imports in the Gulf Coast have been replaced with U.S. tight oil production.

Do Gulf refineries get saturated?

There is a possibility that Gulf Coast refineries will be overwhelmed with light-sweet crude in the coming 12 to 24 months. Once crude reaches the Gulf Coast, it has limited options. Current U.S. laws forbid exports except to Canada and other countries in very limited quantities by special permit, and there is a shortage of Jones Act vessels required to transport crude between domestic ports. Therefore, once U.S. crude has reached the Gulf Coast, it must be processed by refineries or stored locally.

The recent trend has been for Gulf Coast re- fineries to back out foreign crudes to accommodate incremental U.S. and Canadian production, the majority of which is light-sweet. How much more light-sweet crude can they conveniently use? Not much, because Gulf Coast refineries have been configured to accommodate heavier crudes expected from South America.

The amount of light-sweet crude being imported by Gulf Coast refineries is down more than 90% from pre-tight oil revolution levels (see Figure 4, compiled from EIA data). Comments from industry leaders and data from the EIA both suggest that there is a significant probability of Gulf Coast refineries becoming saturated with light-sweet crude within the next 24 months.

Rail to the rescue

The amount of Bakken production winding up in the Gulf is a factor in determining whether the Gulf Coast refinery complex will become saturated with light-sweet crude. Railing crude out of the Bakken is currently the only large-scale, economic option for moving domestically produced tight oil to non-Gulf Coast refineries. Because crude produced in the Bakken had limited pipeline takeaway options (unlike the Permian and Eagle Ford crudes), the midstream industry was quick to build many rail terminals in the region. Today, rail-loading capacity in the Bakken comfortably exceeds the region’s total crude production.

Shipping crude by rail (and then often barging it) to U.S. refineries costs significantly more than equivalent pipeline transportation, but with that cost comes added flexibility. Rail can reach many destinations that pipelines cannot access. Today, more than 60% of Bakken production is transported by rail. Of that amount, greater than half is railed to the East Coast and about one-fifth is railed to the West Coast. Bakken crude reaches many more refineries than either Eagle Ford or Permian crudes.

Bakken crude is railed to the East and West coasts when the economics make sense. It re- ceives (approximately) the Brent price on the East Coast, the Alaskan North Slope price on the West Coast, and the WTI price at Cushing. The total cost of transporting a marginal barrel of Bakken crude to an East or West Coast refinery (rail, barge and terminal fees) is about $17/bbl vs. $8/bbl to Cushing.

As long as the Brent price exceeds the WTI price by about $9/bbl, it makes economic sense to move Bakken crude to the East or West Coast rather than to the Gulf Coast. In practice, several factors besides the real-time prices of crudes determine where barrels are sent. But over a multimonth time frame, crude movements usually respond to locational arbitrage opportunities.

Future scenarios

Two major factors determine U.S. crude price relationships today: Brent prices and the supply/demand balance of light-sweet crude in the Gulf. Because of flexibility regarding where Bakken barrels are sent, there is some correlation between the two factors.

If the Brent price remains strong, then Bakken crude will be shipped to the East and West coasts. Fewer Bakken barrels in the Gulf will reduce the likelihood that refining capacity of light-sweet crude will reach saturation. As a result, Bakken, WTI, LLS, Eagle Ford and Midland crude prices all benefit from a robust Brent price.

Conversely, if the Brent price weakens materially, more Bakken crude will be sent to the Gulf Coast rather than the East and West coasts, and the chances of oversupply in the Gulf will increase. Bakken, WTI, LLS, Eagle Ford and Midland crudes will all feel some consequent pressure.

If supply and demand remain balanced for light-sweet crude in the Gulf Coast, then transportation and grade-related price adjustments to WTI are likely to persist: approximately +$3/bbl for LLS, -$1/bbl for Eagle Ford, and -$2/bbl for Midland. The WTI price is likely to be well- supported in this environment.

On the other hand, if the Gulf Coast becomes saturated with light-sweet crude, WTI, LLS, Eagle Ford and Midland crudes will be subject to downward pressure. Furthermore, restrictions embedded in transportation contracts with take-or-pay clauses may result in periods where the normal price adjustments described above are disrupted. This has led some energy analysts to forecast that LLS may trade at a discount to WTI in the near future. If it does, discounted LLS prices would arrest the flow of light-sweet crude to the Gulf Coast until the market rebalances.

Figure 5 summarizes these relationships. On the vertical axis is the Brent price and on the horizontal axis is the supply/demand balance of light-sweet crude in the Gulf. In the quadrants are hypothetical prices for the various U.S. crudes under the given conditions.

Figure 5: The Brent price and the availability of the Gulf Coast refinery complex to handle incremental light-sweet crude will be important drivers of U.S. oil prices over the next 24 months. Here are hypothetical prices in four different fundamental environments.

Figure 6A: Forward curves are heavily discounted and show large Brent-WTI and Brent LLS differentials.

Figure 6B: Forward differentials to WTI for LLS and Midland WTI reflect a balanced Gulf Coast crude market.

Forward curves, hedging

Figure 6A shows forward prices and Figure 6B shows forward price differentials for U.S. crudes where available. (Note that there is no forward contract for Bakken or Eagle Ford crudes, and the Midland curve is illiquid beyond 12 months.) The forward curves are heavily discounted. The large discounts for U.S. crudes relative to Brent reflect the anticipated growth in the U.S. crude supply going forward. Forward LLS and Midland differentials to WTI reflect transportation fee-related price adjustments expected for a market in equilibrium.

The fundamental landscape for oil production in the U.S. is changing rapidly. At the time this article was written, Brent oil prices were near
$110 and the appetite of Gulf Coast refiners for U.S. oil was strong. Readers should appreciate that this is the best-case scenario (Figure 5, Quadrant I) for U.S. producers. Growing U.S. production will likely have an adverse impact on both absolute prices and basis relationships (Quadrants II and IV). Should the Brent price revert to the lower end of its trailing three-year range, that would pressure all U.S. crude bench-marks (Quadrants III and IV).

A closer look at a shift from Quadrant I to Quadrant IV illustrates an important point for U.S. producers: If U.S. crude price fundamentals turn down, absolute prices will fall far more than basis differentials will in dollar terms. For example, we expect that the premium LLS has to WTI could fall by $3- to $4/bbl if Gulf Coast refineries cannot handle any more light-sweet crude. In that event, LLS and WTI prices might fall by $25/bbl or more because PADD 2 and PADD 3 supplies will be abundant.

A study of crude flows in the U.S. reveals that while growing production threatens existing basis relationships, the threat to the overall level of crude prices in PADD 2 and PADD 3 is more significant. Given this, producers should remain more concerned about absolute price changes for U.S. crudes than about relative price changes. The fundamental factors that drive basis are also driving absolute prices, but to a greater extent.

Hedging production for 2015 and beyond is complicated by discounted forward prices. Despite the discounts present in today’s forward curves, it is important to remember that crude prices can go lower. Quadrants II, III and IV in Figure 5 suggest that U.S. crude prices are likely to settle below today’s forward prices if supply overwhelms demand in the Gulf Coast or if the Brent price weakens. If both these happen together, as in Quadrant IV, U.S. crude prices will likely settle markedly lower. Should any of these outcomes unfold, it would be paramount for U.S. producers to manage the absolute commodity price risk to protect revenues.

Conclusion

U.S. crude fundamentals have changed pricing relationships dramatically. Unfortunately, the combination of discounts to Brent and discounted forward curves is not ideal for producers. Nonetheless, U.S. E&P companies should protect themselves. No doubt, hedging poses risks. But not hedging may pose the greatest risk of all. In the next two years, lower Brent prices and/or Gulf Coast refinery saturation are a real threat to the oil prices U.S. producers enjoy today. Given any of these scenarios, an effective hedging program will prove necessary to achieve revenue targets.

Wayne Penello is the president and founder of Risked Revenue Energy Associates (R^2 or "R-squared.") Rishi Sahay, CFA, is an analyst at R^2.