Why U.S. Oil Markets Reflect Supply & Demand

Increased oil production in North America during recent years has been well publicized. The U.S. Energy Information Administration (EIA) reports that, since 2005, Canadian oil production has increased steadily by 1 million barrels/day (mb/d). In the United States, production has risen by more, and at a faster rate – 3.5 mb/d in less than five years.  This has led some reputable institutions and analysts to project that by 2020 the United States will be the world’s largest producer of crude oil.

Regardless of the actual ranking of U.S. production compared to others, there can be no dispute that North American production has increased significantly, is expected to continue increasing significantly for the foreseeable future, and constitutes a significant component of international fundamental supply and demand for oil.


Price Impacts

All other things being equal, the increased production in North America should have led to lower crude oil prices in North America versus the rest of the world. Furthermore, given the rapid continuing decline in North Sea production that predates the increased production in North America, North Sea prices relative to North American prices should have increased. Of course, as always in the real world, it is not the case of ‘all other things equal’; although enough stayed ‘equal’ for it indeed to be the case that North Sea prices rose relative to U.S. prices, not all such impacts have been equally incurred or sustained during the entire period.

Part of the reason for this is that expansion of the oil distribution system in North America trailed expansion by the oil production system by one to three years, depending on who is doing the counting and how they are doing it.

During this period, however long one assesses it to be, Midcontinent North America supply increased relative to U.S. Gulf Coast supply and prices reflected it. A logical consequence  of this, completely consistent with the fundamentals,  is that the differential between Midcontinent and U.S. Gulf Coast prices for crude oil widened in favor of the Gulf Coast. For instance, using Refiner Acquisition Cost of domestic produced crude oil reported by the EIA, beginning in Spring 2011, the differential increased to about $5/ barrel, and eventually reached $19/barrel during Fall 2012, immediately prior to the implementation of the Seaway pipeline reversal that increased flow capacity from the Midcontinent to the Gulf by approximately 400,000 b/d.

After the Seaway reversal, which is only part of the increased flow capacity from the Midcontinent to the U.S. Gulf, the differential quickly decreased, reaching about $2/barrel in June and July , the two most recent months for which these data were reported at the time of preparing this note. $2/barrel is slightly higher than where the relationship stood before Spring 2011, but is very close. I used Refiner Acquisition Costs (RAC) because they are documented and authorized by the EIA and represent what refiners actually paid for their crude oil.

Notwithstanding, it is highly likely that the distribution of crude streams included in these data changes from month to month, so these data do incorporate changes in specifications that are not accounted for. Using an alternative stream of prices, such as reported spot prices, entails comparable, if different, compromises in data consistency. The overall purpose here is to give an indication of the scope of the relationship between Midcontinent and U.S. Gulf prices, and RAC does that.


Price Analysis North American Crude Oil

An attractive and commonly accepted feature of the U.S. market is that U.S. crude oil prices, including WTI, reliably reflect fundamental supply and demand. In large part, the commercial market is expressly structured and organized to accomplish this. The market mechanisms, including delivery components of the commercial U.S. oil market are based on straightforward designs, intended to attract participation and support and build commerce; they are uncomplicated and lack artificial barriers to entry, and this leads to active arbitrage across the vast distribution system. The result is that U.S. commercial markets are directly accessible to thousands and, driven by arbitrage, incorporate significant levels of transparency and competition.

Accordingly, prices respond to supply, demand, and competition – exactly what Midcontinent and U.S. Gulf supplies are experiencing and what we illustrated above. The reason prices have converged is because the capacity to move crude oil from production areas in the Midcontinent to the rest of the United States, including the Gulf Coast, has increased dramatically – by nearly 2 mb/d over the past several years, with an additional 1.5 mb/d to the Gulf to be added during Q4-13 and Q1-14. The EIA reports that rail cars are transporting 1.4 mb/d as of mid-2013. As mentioned earlier, the Seaway reversal added 400,000 b/d capacity to the Gulf and the looping of its lines is scheduled to double that during Q1-14.

The Southern leg of the Keystone pipeline began operation in January and should ultimately add 750,000 b/d capacity. In addition, the Magellan pipeline is scheduled to bring on another 250,000 b/d of capacity in Q1-14. The market has fully embraced the additional capacity and will continue to do so as even newer capacity is added.

The EIA also provides a historical record of pipeline, tanker, and barge movements between PADDs. It has not yet been able to incorporate the rail car movements into this specific record series. Until recently, the flow from the Gulf to the Midwest dominated the reverse direction. According to the EIA, as recently as 2005, there were months in which more than 2 mb/d of crude oil flowed from the Gulf to the Midwest. This has steadily declined since then, but it is still the case that monthly flows average from 860,000 b/d to over 1 mb/d (Q4-12). These fundamental data are consistent with the other fundamental observations about increased production. Clearly, the need to ‘import’ crude from the Gulf to the Midwest has diminished as Midcontinent production has increased.

Moreover, the reverse flow – from the Midwest to the Gulf – has increased steadily since U.S. production began rising in 2008, shooting up in particular during 2013. According to EIA, in January 2008 the flow was 63,000 b/d; in both March 2013 and July 2013 the rate was over 500,000 b/d. The increased pipeline capacity means the conditions are set in motion for this to increase further easily.

On top of this, from March through July 2013, EIA reports that imports of crude oil into the Gulf have decreased by 1.8–2 mb/d since 2010, which clearly impacts markets outside the U.S. In other words, the supply of oil to the rest of the world – conceptually from the U.S. Gulf – has increased by nearly 2 mb/d over the past three years. Increased U.S. supply is directly and significantly impacting world supply.

From the perspective of fundamental market supply and demand information, U.S. market participants are extremely well-informed, indeed the best-informed in the world by a wide margin. In addition to what is referenced above, there are well-known series on weekly inventory reports for crude and products, each region (including Cushing, Oklahoma, the delivery and pricing point for WTI), and the entire United States. These data are delivered within three business days, which makes them approach the equivalent of real-time information for fundamentals. In addition, market participants have access to weekly updates of refinery inputs and capacity utilization on a regional and national basis.

One conclusion to draw from the trove of data is that U.S. oil markets, governed by arbitrage, cannot elude the discipline of fundamental supply and demand. Our own reference to the relationship between the Midcontinent and Gulf Coast served as an illustration of this point, demonstrated with three different types of data streams for each location. (The data streams include production, price, and movements. In addition, a fourth stream applied to the Gulf Coast imports.)

So far, we have added to the well-documented historical testimony that U.S. oil prices, including WTI, are driven by arbitrage and are highly responsive to fundamentals that are transparent, as well as being supported by underlying commercial market mechanisms that are also fundamentally transparent and fair.


North Sea Fundamentals?

A fair starting point is to attempt to identify a relationship for North Sea oil and fundamental supply and demand information comparable to that which exists for U.S. crude oil markets, including WTI. Now, one very important piece of fundamental information is provided once each month, in advance, by the commercial producers: the

Production and loading schedules for the respective crude streams. Beyond that, fundamental supply and demand information for the North Sea does not exist in terms of the detail and timeliness for which it exists for the United States. Nobody in authority compiles such fundamental information for the North Sea.

The International Energy Agency (IEA) does compile fundamental supply and demand information and provides a substantial amount of valuable analysis of the world; but its data flow has a substantial lag of more than three months, when taking revisions into account. However, there is no official source of fundamental supply and demand information for the North Sea, beyond the scheduled loadings and a summary report of production by the IEA (with its lengthy lags), and this does not always detail its ‘BFOE’ components (Brent, Forties, Oseberg, and Ekofisk, the constituent streams that currently make up what is colloquially referred to as ‘Brent’ in the oil market).

There is ambiguity in what should define North Sea fundamentals.  The proof of this is that there is no shortage of subjective ruminations about the BFOE market, many of which are very insightful, but those ruminations are dominated by unconfirmed reports of commercial activity and inferences thereof, rather than by objective supply and demand information;  all of this constitutes market commentary rather than market fundamentals.

This does raise two related questions: if there essentially is a lack of objective fundamental information by which to measure BFOE’s price movements, how can one confirm that BFOE is driven by fundamentals? Also, if BFOE pricing were not driven by fundamentals, what is it driven by?


BFOE Cash Forward and Physical Markets

The BFOE ‘market’ is mired in layers of different instruments or mechanisms. Most of the layers have been added over time as part of an effort to cope with diminishing North Sea oil production. Our focus is on two very important layers: the BFOE cash-forward market – full cargos – which is the traditional core of the BFOE (and its predecessor Brent) market and the Physical Cargo market – Dated BFOE.

We will look closely at the Platts Dated price because it is that reference that is incorporated  into almost all the actual Dated Physical cargo transactions  as well as many pricing formulas used by national oil producers to price their oil. The relationship between these two mechanisms is straightforward, but indirect. Platts Dated is not directly related to BFOE forwards:

• BFOE cash-forwards are forward contracts for 600,000 barrel cargos to be delivered at the loading terminal for B, F, O, or E at Seller’s discretion during the delivery month. The Seller owes the Buyer a minimum notice period – currently 25 days – that the delivery will take place.

• BFOE Dateds are the same BFOE cash-forward contracts after the Seller has provided the Buyer with the date of loading for the contract. They are referred to as physical cargos because they are legally destined to be loaded and delivered with physical oil. Dated contracts are typically priced at a differential to Platts Dated prices for a series of days.

Platts Dated price assessments are published daily. It is our understanding that they are derived from two of its Market on Close (MOC) price discovery mechanisms: the Partial Brent Forwards, and the contract for difference (CFD) between Partial Brents and Dated Brent. Partial Brent Forwards are cash-settled obligations between any matched seller and buyer for 100,000 barrel equivalent obligations. They are cash-settled, equivalent to Swap transactions, using Platts’ Partial Brent assessment as the floating price with one exception: if the same counterparties enter into six transactions  with each other for the same contract month, they are obligated to turn the six obligations into a full forward cargo contract. Platts has assured us that this happens more than occasionally and market participants abide by the rule.

Nobody suggests that this is the usual outcome but it does occur. The second price discovery mechanism (the CFD between Partial Brents and Dated Brent) is exclusively cash-settled.  When one adds the “prices” from each of these “markets” – the sum of partial Brent with the difference between Partial Brent and Dated Brent – one derives Platts Dated Brent. Accordingly, Platts Dated Brent, the most commonly utilized reference for Physical BFOE contracts,  is derived from two series that are structured to cash-settle; one which always does so, and the other which does so most of the time, with some exceptions.

The Partial Brent and CFD MOC price discovery processes are clearly important mechanisms crucial to pricing the physical BFOE market. One of them entails a possible delivery obligation, but only as an unlikely coincidence. The other entails no delivery obligation. Furthermore, the price discovery processes are not specifically market mechanisms; they support transactions and bids and offers, but these mechanisms are expressly designed to discover value at a defined moment in time. The transactions and bids and offers are tools to reach that goal.

By comparison, markets are expressly defined by their bids, offers, and transactions, and one of the market outputs is discovered value.

As such, are these price discovery processes driven in a similar way to those in the U.S. oil market – participants comparing physical delivery alternatives and performing arbitrage to determine prices? It is not clear that there is a role for arbitrage in these processes. This is not to suggest there is anything inappropriate in this, but if there is no role for arbitrage, is there a role for market fundamentals? There really is nothing that compels physical market supply and demand discipline to be administered through these mechanisms.

Bids and offers can reflect views and expectations of market fundamentals and may incorporate them, but there is no physical market consequence if they do not. It is our understanding that, ordinarily, the MOC assessments against which transactions are cash-settled are endogenously determined within these processes without any specific regard for market fundamentals.

Unlike market mechanisms with either physical delivery obligations or cash-settled mechanisms calibrated to physical market transaction values, these are pure price discovery mechanisms that can apparently be independent of physical fundamentals.

To the extent they are independent, they essentially amount to being an elaborate price negotiation platform; constituting a sophisticated means by which sellers and buyers will determine  sale and purchase prices, ultimately for physical oil that uses this series as a price reference. And the continuing reliance by market participants on such mechanisms to serve as a base reference price for other important transactions constitutes a strong endorsement of their value; but does it mean they reflect market fundamentals?

Do BFOE cash-forward cargo transactions ultimately govern Platts Dated BFOE? One of the difficulties in trying to answer this is that the cash BFOE market conducts itself non-transparently. Very few transactions are publicly reported so there is no public window by which to view any possible price discovery. By comparison,  Platts conducts its price discovery processes with a high degree of transparency.

Sidestepping the lack of BFOE forward market transparency, the arbitrage that could take place would be between the forward cargos and the dated cargos. One would expect some degree of convergence to take place between the forward and dated markets, but the lack of transparency of the forward market makes it difficult to uncover any supporting evidence. At the same time, no such convergence needs to take place between the Platts Dated and BFOE Forwards. Consequently, there really is no arbitrage mechanism between Platts MOC price discovery mechanisms and the BFOE cargo market. Accordingly, it is difficult to envision what principles would govern Platts Dated calibrating in lock-step to price impulses from the BFOE forward market.

By process of elimination, this would suggest that Platts Dated’s price discovery processes may lead the BFOE forward cargo market. Whether they lead or not, they do not seem to follow. Outside of negotiation motives, there do not seem to be obvious governing principles to these processes, including any predicated in fundamental supply and demand.



We still need to define what constitutes the relevant fundamentals for the North Sea and see if those fundamentals are actually ever assembled or calculated. In addition, we still need to determine what are the prime driving forces in the North Sea market and whether fundamentals are at the core or something  else altogether.

It does appear that we can state that U.S. market benchmarks incorporate arbitrage from the physical market, reflect fundamental supply and demand, and are subject to confirmation of this by a substantial catalog of authoritative data.

With respect to North Sea benchmarks, the role of arbitrage, and how and if it reflects market fundamentals is not so clear and there is a lack of authoritative data by which to confirm performance.


This article originally appeared in Oxford Energy Forum

Bob Levin is managing director of energy/ commodity research and product development at CME Group.

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