Black Friday 2014: As crude oil prices began their precipitous descent from $100 per barrel (bbl.) to less than $50 per bbl., a specter of protracted gloom washed over oil producers across the globe.

WTI_and_Brent_Crude_Spot_Prices

Energy exploration and production (E&P) companies, which had been generating returns of more than 30% at $100 per bbl. of crude oil, suddenly faced a murkier future. The pessimism afflicting the producer community was perhaps only surpassed by the optimism – or perhaps opportunism – that swept across oil trading desks in places such as London, Houston, Geneva, and Singapore. Traders welcomed the sudden return of price volatility after nearly eight years of historically low levels.

WTI_Crude_Volatility

Enter Contango

If the price crash was unwelcome to the producer community, market participants down the supply chain were not complaining, particularly energy merchants, crude oil storage operators, and refineries. The arrival of price instability was particularly welcome by companies whose business models included exposure to one of the key profit drivers in the energy trading business: the difference between today’s price for crude oil delivery compared with the future price, also known as the time spread or the calendar spread.

Global_Supply_and_Demand_of_Liquid_Fuels

Term_Structure_of_Crude_Oil_Prices

The glut of inventory caused the spot price of crude oil to decline more rapidly than the forward price, resulting in an increase in the time spread. Traders who had secured long-term oil storage capacity at low rates in advance of the crash through ownership of storage facilities or long-term leases with third-party operators were pleased to see the market dislocation. Similarly, storage operators who had not leased all of their storage capacity could suddenly consider raising the rent.

US_Crude_Oil_Cushing_Stocks

After two years of fairly flat and backwardated forward curves – when the difference between the spot price and the 12-month futures contract rarely exceeded $5 per bbl. – the forward curve suddenly flipped into a condition known as contango, where the price for delivery in the future exceeded the price for delivery today by an above-average margin. Similar to the yield curve in interest rates, the term structure of the crude oil market – where the price for future delivery of crude oil is set – can at times present opportunities to earn profit with minimal risk for companies that have the storage capacity – whether leased or owned – and the capital resources to take advantage of it.

12_Month_Forward_Time_Spread

As the market shifted into a steeper carry structure, popular media outlets and research outfits covered the new pricing dynamic in depth. But as market observers evaluated whether an energy merchant could profitably purchase and carry crude, hedge the price risk by selling a futures contract, and still earn a profit, much attention was given to the pure cost of term storage – particularly floating storage held in offshore tankers – with less emphasis placed on an even more important variable: the structure and cost of a merchant’s capital.

As capital providers and advisors to a number of energy merchants, BBH received many inquiries from clients on financing contango trades during this period of price volatility. In this article, we zero in on how a company's cost of capital is a critical and often overlooked variable in determining whether a firm can profit from periods of contango.

The Carry Trade: A Crude Primer

The following variables must be considered when evaluating whether it makes economic sense for a merchant to enter into a contango or cash and carry trade:

Carry_Formula

When the sum of variables 2 through 6, also known as the carrying cost, is less than variable 1, a merchant can in theory earn an arbitrage with virtually no risk by purchasing crude oil inventory today, placing it into a storage tank or offshore vessel, and selling a futures contract. To help mitigate geographic basis risk, the storage must be located near an exchange. As such, given the excess inventory in the marketplace, storing the crude oil for future delivery to a refinery looked like a particularly interesting option for merchants with inventory and access to storage.

What factors drive each of these variables? Variable 1 represents the price for future delivery at a specific location (Cushing, Oklahoma, in the case of the West Texas Intermediate futures contract). Price formation occurs through trading activity on the futures marketplace and is beyond the merchant’s control. Similarly, the second variable is set through trading activity in the spot market. Variables 3 and 4 can vary slightly based on whether a merchant has secured contractual transportation capacity (via rail, truck, or barge) and storage capacity in advance at a predetermined rate. Moreover, the storage cost can differ among merchants based on whether the merchant owns or leases storage facilities, when the storage rate was locked in, if the storage was leased for a period of time, and for how long the lease rate was locked in. Variable 5, though not a major driver of the economics, will generally be a function of a merchant’s scale in the marketplace.

Merchants without the benefit of pre-existing storage capacity secured before the arrival of contango would be out of luck. As the forward curve steepened after the crash, storage operators raised rates to meet increased demand to store excess inventory. Storage – like all commodities – becomes dearer as demand for tank space increases relative to the supply of tank space. As such, unless they had contracted storage in advance at a fixed rate or owned storage tanks, merchants were by and large shut out of the carry trade.

How Much Does Your Capital Cost? Working Capital Budgeting

If the universe of merchants that had secured fixed price storage before the arrival of contango was limited, the number of companies within that universe that could take advantage of the opportunity was limited even further. The key driver of this differentiation is rooted in a simple corporate finance concept known as the weighted average cost of capital (WACC).

We have found that merchants often consider only their debt cost of capital when evaluating whether it pays to allocate a scarce resource such as financial capital to a potentially low returning, albeit low risk, contango trade. Looking at the total carrying costs, financing costs should be lower than storage costs. However, financing costs are generally a function of balance sheet size and other credit variables. As such, this element – variable 6 in the prior formula – tends to differ most among merchants and should establish the marginal cost of carry.

Given the low risk profile, contango deals can typically be funded with high leverage; indeed, the inventory price risk is hedged, the inventory insured, and the oil often stored in or near an exchange deliverable location or very liquid market such as Cushing or Midland, Texas, where it can be turned to cash quickly. However, these trades are rarely 100% leveraged, meaning a merchant must allocate some balance sheet equity to the trade. Furthermore, the leverage typically affects a merchant’s balance sheet leverage – a ratio capped by most commodity finance banks – and thus carries an opportunity cost.

A Tale of Two Contangos

To put it all into perspective, let’s look at a hypothetical but realistic example. In September 2012, with the cash to 12-month time spread at approximately negative $1.00 per bbl., midsize energy merchant Arb-A-Little Energy enters into a five-year take or pay storage contract1 with a well-known operator for 500,000 barrels of storage capacity in Midland. Arb-A-Little agrees to a monthly lease rate of 40 cents per bbl. This contract gives the merchant the option, but not the obligation, to store oil in the facility.

Now fast-forward to November 2014: the cash to 12-month spread widens to almost $10.00 per bbl., peaking at around $9.90 per bbl. in early March 2015. Arb-A-Little’s head oil trader, Stephen Smith, enters the office of CFO Gary Guttchek and says: “Gary, the cash to 12 has widened substantially! We need to fill up the tanks in Midland. I think we could make a big profit; we need to act quickly. I can make almost $2.00 per bbl. doing nothing – just need to get the crude there as quickly as possible. That’s almost $1 million in profit for what doesn’t seem like much work or risk.”

Gary, skeptical by nature, tells Stephen that he will perform some analysis that afternoon and respond to the trading proposal within 24 hours. As he begins to do the analysis – looking at the variables described in the earlier formula – certain variables are easy to quantify: the cash price in Midland, the company’s previously locked-in storage and insurance costs, and the futures strip for WTI crude oil.

But calculating the financing costs requires a bit more reflection. Arb-A-Little’s line of credit from a regional bank bears an effective interest rate of 3%, and the bank requires that the company maintain at least 20% equity relative to total assets at all times. While the company could scramble to obtain off-balance financing from an alternative source, typically in the form of a short-term repurchase agreement, the costs and complexity are high, and time is of the essence. To fund the transaction and use the full storage capacity, Gary would have to draw down approximately $30 million on his line of credit, tying up a significant chunk of liquidity and depriving Arb-A-Little of the ability to capitalize on unrelated trading opportunities, which may generate superior returns for the shareholders.

Gary begins doing the math and concludes the company’s WACC is actually 8.6%, assuming a capital structure comprising 80% debt and 20% equity, a cost of debt of 3%, and a cost of equity of 35% (representing the company’s average return on equity over the past three years), and assuming a 35% federal corporate tax rate. Gary even uses the capital asset pricing model to back into the cost of equity and calculate a number in the same range. Suddenly, the economics don’t look so compelling at the current $10 per bbl. spread. In fact, now equipped with all of the necessary information, Gary calculates that the company would actually generate a net present value on the trade of negative $1,959,764 using the 8.6% number as the discount rate.

In order to generate a positive net present value given these assumptions, the spread would need to expand to around $14.50 per bbl. Even in this simplified analysis, Gary has yet to factor in the potential location basis risk – that in which the trader could have to move the oil to Cushing in order to realize the WTI price. The change in the Midland/Cushing location spread over the carrying period could further erode or enhance the profit on changes in this pricing relationship. Now confident in his position, Gary goes back to Stephen and delivers a clear “no” decision on the trade.

Now let’s take Arb-A-Little’s much larger global competitor, Arb-A-Lot. Due to its scale, Arb-A-Lot was able to negotiate a slightly better storage rate of 35 cents per bbl. around the same time in 2012 and at a nearby location with direct access to a pipeline. On the financing side, the differences become even starker. Arb-A-Lot’s line of credit from a consortium of international banks carries an effective interest rate of just 1%. What’s more, the company’s leverage covenants are far less restrictive, requiring the company to maintain a minimum equity level of only 5% relative to total assets. Given the capital structure, Arb-A-Lot focuses more on high volume/low margin business and has also generated returns on equity in the 35% range over the past few years.

Arb-A-Lot is in a different position. With these carrying costs locked in, as shown in the nearby chart, the company can generate a net profit of $3.40 per bbl. Assuming a 500,000 barrel trade, Arb-A-Lot’s trade would generate a net present value of approximately $890,539. And the major difference lies in Arb-A-Lot’s WACC of 2.4%, compared with Arb-A-Little’s of 8.6% (calculated using the same corporate tax rate). Arb-A-Lot’s CFO gives its head trader the green light to execute the trade.

While market participants evaluate the attractiveness of this arbitrage opportunity, conditions begin to change as prices respond to the behavior of companies like Arb-A-Lot. By purchasing crude oil in the spot market, Arb-A-Lot bids up the cash and puts some downward pressure on the futures price given hedging associated with the trade. Not surprisingly, the companies with lower costs like Arb-A-Lot win the cost of capital competition and correct the temporary market dislocation. The efficient market returns, where earning a “risk-free” profit is next to impossible.

ARB_Chart

There may be temporary arbitrage opportunities in a contango market, but so long as the most creditworthy companies have access to liquidity, they will likely keep the time spread relatively narrow. The conclusion may be unsurprising, but few have recognized that the contango trade is ultimately a cost of capital competition – one that will likely always be won by companies with the cheapest capital.

This publication is provided by Brown Brothers Harriman & Co. and its subsidiaries ("BBH") to recipients, who are classified as Professional Clients or Eligible Counterparties if in the European Economic Area ("EEA"), solely for informational purposes. This does not constitute legal, tax or investment advice and is not intended as an offer to sell or a solicitation to buy securities or investment products. Any reference to tax matters is not intended to be used, and may not be used, for purposes of avoiding penalties under the U.S. Internal Revenue Code or for promotion, marketing or recommendation to third parties. This information has been obtained from sources believed to be reliable that are available upon request. This material does not comprise an offer of services. Any opinions expressed are subject to change without notice. Unauthorized use or distribution without the prior written permission of BBH is prohibited. This publication is approved for distribution in member states of the EEA by Brown Brothers Harriman Investor Services Limited, authorized and regulated by the Financial Conduct Authority (FCA). BBH is a service mark of Brown Brothers Harriman & Co., registered in the United States and other countries. © Brown Brothers Harriman & Co. 2019. All rights reserved. PB_03082_2019_09_06

1 Take or pay contract: A contract that requires the buyer to pay for a contractually determined minimum volume, even if delivery is not taken. Its function is to move the volume risk from the producer to the buyer.