The boom in North American crude production, both U.S. and Canadian, has significantly impacted not only absolute crude prices, but perhaps more importantly the differentials between individual grades and from different regions. As rapid growth from tight oil fields like North Dakota’s Bakken, South Texas’ Eagle Ford, and West Texas’ Permian, along with Western Canadian oil sands reserves, has exceeded existing pipeline infrastructure. We have seen a variety of crudes become “stranded”, resulting in huge differentials and significant volatility.
As with all prices and price relationships, absolute levels and differentials between grades and regions will be driven by the relative supply/demand growth patterns of the various grades of crude and their accessibility to markets. In our recently released North American Crude & Condensate Outlook (NACCO) we have analyzed in detail how all of these factors will change over the next 10 years, and forecast annual average prices and differentials for all of the key crudes in all of the major markets in the United States.
While we are not trying to “call the market” for short-term or trading purposes, we do endeavor to develop a complete assessment of market variables, likely commercial reactions and price differentials which reflect these conditions. In our NACCO we evaluated two scenarios, a Low Case production of 9.5 MMBPD in 2022 and a High Case production of 12.0 MMBPD in 2022. Considering all relevant supply and demand fundamentals, we expect the average price of a barrel of oil to range between $80 and $120 a barrel on a sustainable basis.
Both supply and demand factors will serve to keep prices in this range. As prices move towards or below the lower “floor” of $80 per barrel, production from the more expensive plays will fall and demand will increase. At levels above $120 per barrel, production will increase while demand is restrained. The most important factor creating the “ceiling” is the large surplus capacity existing in the world, a level which is expected to exceed 7 MMBPD as North American production continues to grow rapidly and the call on OPEC crude declines.
More important to the bottom lines of refiners than the absolute price of crude are the differentials between crudes of different quality and produced in different locations. Within the U.S., WTI, LLS and other domestic sweet crudes have historically been priced fairly close to each other, with differentials related to quality differences between the crudes. Since the U.S. has been a significant importer of waterborne light sweet crude oil, the pricing relationships between WTI and LLS vs. Brent have generally reflected quality-adjusted import parity at the USGC.
This resulted in the domestic crudes being priced higher than the waterborne crudes by the approximate cost required to deliver the international crudes into the U.S. market, adjusted for any quality differences. These historical relationships, both between domestic crudes themselves, and between domestic crudes and waterborne crudes, have shifted dramatically in the last few years as a result of the explosive growth of U.S. production of light crude.
With production growth from inland crude fields exceeding the capacity of pipeline infrastructure, discounts for the landlocked crudes vs. those available at the coasts exploded. The discount for WTI vs. LLS moved into double digits in 2011 (reaching $30 per barrel and averaging over $17 per barrel). Both the announcement in late 2011 that there would finally be a pipeline link from Cushing to the USGC (the reversed Seaway pipeline), and the actual start-up of the system in May of 2012, the WTI discount reduced temporarily to the low double-digits, but in each case, it soon returned to previously-elevated levels with the 2012 average exceeding that of 2011 at $17.55 per barrel.
The start-up of an expansion of Seaway in January 2013 had even less of an impact on the discount, partially due to problems which limited throughput to well below the design capacity of 400 MBPD. As a result, the discount was higher yet in the first quarter of the year, averaging $19.60 per barrel. The start-up of Magellan’s reversed Longhorn pipeline in April, however, seems to have finally been the “straw that broke the camel’s back” when it comes to the WTI discount. Although initial flow in the line (which takes crude directly from the Permian to Houston area refineries) is only about 75 MBPD, this has been enough to finally take the LLS – WTI differential into single digits, averaging less than $10 per barrel during the month of May and falling to levels well below that in June.
With the Permian/Cushing to USGC bottlenecks removed, now we are seeing a bottleneck develop between Houston and Louisiana. Ultimately, this constriction will also be removed, with the completion of Shell’s Ho-Ho reversal all the way to St. James (expected in the second half of this year) and we expect the WTI price to trade at a level equal to pipeline transportation and quality-adjusted parity with LLS on the USGC (about $6.00 per barrel for LLS/ (St. James) minus WTI (Cushing).
Similar developments can be expected in price relationships between other domestic crudes as midstream infrastructure (including rail) is built out. It should be noted that there will continue to be periods when differentials become volatile, in response to events such as refinery shutdowns/pipeline closures or other developments affecting the regional sweet crude supply/demand balances, but in general we expect volatility to be much reduced from the levels seen over the last two years. When it comes to measuring the relative competitiveness of U.S. refineries vs. those in other parts of the world, the Brent vs. LLS differential is a key indicator.
As a result of the crude boom, a fundamental shift in this relationship is taking place from past levels. Historically, with significant volumes of sweet crude imports moving into the U.S. market, Brent (and crudes priced off of Brent) traded at freight- and quality-adjusted parity to LLS at the USGC, generally resulting in a $2 to $5 per barrel LLS (St. James) premium over Dated Brent. This lower cost for light sweet was one of the few advantages that European refiners have enjoyed vs. U.S. refiners that can run only light sweet crudes. With waterborne light sweet imports being rapidly displaced by booming domestic production, we have already seen glimpses of the future, with LLS trading at a discount to Brent at times over the past two years in reaction to events such as the loss of Libyan crude, rumors of SPR crude releases, pipeline start-ups and other situations.
These periods have not been sustained, as light sweet imports have not yet been totally displaced, and volatility in the relationship has been significant. The differential averaged only $0.10 per barrel (LLS – Brent) in 2012, but reached as high as a $6 premium and as low as an $8 LLS discount. In March of 2013, LLS moved back to a fairly significant premium over Brent (averaging almost $4.50 per barrel) as a result of the bottleneck between Houston and St. James, issues with Brent availability, and other short-term developments. This premium remained relatively high through April and most of May. Then moved to a LLS discount for a while in late May/early June and has again moved to where LLS has trading above Brent for most of June.
Although we don’t have a crystal ball, and certainly can’t predict short-term price movements, we do believe the well thought out supply/demand based assessments made in TM&C’s NACCO are a good basis for evaluating long term decisions by all members of the crude supply chain (producers, midstream operators and refiners). The crude oils and regions featured were chosen based on their commercial importance and transparency. Crude oils from each of the six major grades we studied (Heavy, Medium, Light Sour, Light Sweet, Super Light and Condensate) are included, and a total of almost 60 separate price series are forecasted. For more information on the study, please contact me or any member of our Outlook Team.