Is the spread dead?

On July 10, the discount on domestic benchmark West Texas Intermediate (WTI) relative to the internationally traded Brent crude — which had ballooned to more than $10 per barrel for most of 2011 and 2012 — deflated to little more than $2, the lowest in 2 1/2 years.

In this week’s issue, we’ll discuss the implications of this profound change for refiners, domestic oil producers, pipeline operators and railroads.

Refiners

The vanishing spread is terrible news for the refining industry, which has for two years sold gasoline tied to the price of Brent, while buying much of its crude at a discount even to the WTI from the booming domestic tight-oil basins and western Canada. The discount of these crudes to the WTI has been on the wane for months, so they’ve gained even more ground than the WTI on the Brent.

Refining stocks have started to price in assumptions of sharply diminished profits, not only because of the diminished differential but also as a result of lower refining margins, as each producer has sought to cushion the earnings hit by maximizing its refineries’ output.

Tesoro (NYSE: TSO) and HollyFrontier (NYSE: HFC) have lost roughly 10 percent apiece since being added to the portfolio a month ago, and may yet go significantly lower. Holly Frontier, which is more dependent on access to cheap domestic crude than some of its larger rivals, has already broken decisively below its 200-day moving average, while Tesoro and Aggressive Portfolio holding Marathon Petroleum (NYSE: MPC) test theirs. Marathon was already a Hold, and now we’re calling TSO and HFC Holds as well.

The 10 percent discount might be light relative to the increase in bottom-line risk over the last month.

Many analysts are defending the refining stocks at this point, and there are good reasons to believe the Brent-WTI spread will expand again soon enough. But the market has a mind of its own, and its forecast for refiners is not so sunny.

If the spreads reflate and the stocks lift, we’ll happily change those Holds to Buys down the road. But at current levels of volatility and risk refining stocks are a poor destination for new money.

Just keep in mind that the published crude spreads can only approximate the effect of the changing cost of inputs on the industry’s bottom line.

To really understand a refiner’s prospects is to understand the oil slate, or the mix of crude grades, that company runs in its particular refineries, and the price relationship of that oil to the optimal mix of finished products those refineries can produce. “Brent-WTI differential” merely approximates this relationship, and the appropriate caveats must be recognized.

A better metric would be the Brent-Bakken differential for many mid-continent refiners, but this is not as simple as it may seem. My friend Douglas MacIntyre is the Director of the Office of Petroleum and Biofuels Statistics for the Energy Information Administration. He explained to me in a recent email the problem of getting Bakken crude pricing information, and how one might approximate that from EIA data:

“The challenge with Bakken prices is location.  Bakken prices are quoted at Clearbrook, MN and at Guernsey, WY — and Platts now offers Bakken quotes at both locations — but a subscription is likely needed. That said, Bakken crude is also sold at the wellhead — at substantial discounts to the Clearbrook and Guernsey prices. The Bakken crude that moves east and west by rail we think is typically sold at the wellhead — because unit train loading facilities are not necessarily in Clearbrook or Guernsey.

We get the Clearbrook spot price for Bakken for our internal analysis from Bloomberg.  But you do need access to a Bloomberg terminal to get that.

As far as EIA data, all we have is a monthly average for the 1st purchase price of crude oil from North Dakota (see the page at http://www.eia.gov/dnav/pet/pet_pri_dfp1_k_m.htm).  The 1st purchase price is thought of as approximately the wellhead price.  This is not specifically for Bakken crude oil, but it would be dominated by Bakken crude.”

Cloudy as the data might seem, the trend has been crystal clear. WTI for August delivery closed at $106.52 a barrel on Wednesday. Just over two weeks ago it closed at $93.81. I do think the WTI won’t go much higher in the short term, and that its discount to Brent might increase again soon. But in the meantime profits will disappoint.

However, what’s bad news for refiners isn’t bad news for everyone.

Oil Producers

Higher WTI prices are good for oil producers in the Eagle Ford, Permian Basin, Bakken, and Niobrara basins. The current pricing for most domestic crudes is $8-$10/bbl higher than it was in June, which is good news for several of our portfolio companies.

Data Sources: EIA, Bloomberg, and Plains All American Pipeline Price Bulletins

Growth Portfolio holding EOG Resources (NYSE: EOG) is the fifth largest non-integrated oil and natural gas company in the United States, and the largest oil producer in the Eagle Ford formation in Texas. EOG is also one of the top five oil and gas producers in the Bakken.

EOG is by far the largest horizontal crude oil producer in the US, with nearly 200,000 barrels per day (bpd) of crude oil produced by horizontal drilling at the end of 2012. EOG increased its crude and condensate output by 39 percent in 2012.

The company’s stock has been an excellent performer over the past 12 months, rising 55 percent. EOG has an Enterprise Value/EBITDA ratio of 9.3 and the company pays a modest dividend, currently yielding 0.5 percent on an annual basis.

EOG is currently a Best Buy in the Growth Portfolio. Buy EOG up to $145.  

Continental Resources (NYSE: CLR) was one of the pioneers in the Bakken formation. CLR was the first to complete a horizontal well in the Three Forks formation (which lies underneath the Bakken), and to date the company has drilled about 20 percent of all Three Forks wells. Today, Continental is the largest leaseholder and oil producer in the Bakken with more than 1.1 million acres leased.

CLR has also been a pioneer in pad drilling, which allows the drilling of multiple wells from a single pad. This approach results in an estimated 10 percent cost savings on the drilling and completion of each well.

Continental’s Enterprise Value/EBITDA ratio is 9.3. The share price has risen 38 percent over the past 12 months, and CLR is a Best Buy in our Aggressive Portfolio. Buy CLR up to $110.

One of Continental’s biggest competitors in the Bakken is Whiting Petroleum (NYSE: WLL). Whiting is the second largest oil producer in North Dakota, averaging 82,500 BOE (barrels of oil equivalent) of production in 2012 across more than 700,000 acres of leased land. Like Continental, Whiting has been actively engaged in pad drilling, citing a cost savings of more than $500,000 over single wells drilled in its Pronghorn field. At the end of 2012, Whiting had 10 rigs capable of pad drilling in North Dakota.

Whiting’s Enterprise Value/EBITDA ratio is 5.1. Whiting is a Best Buy in the Conservative Portfolio up to $57.

Oasis Petroleum (NYSE: OAS) is a pure Bakken/Three Forks play, with 335,000 leased acres in the Williston Basin. Oasis has only been a public company for three years, but the share price has risen 163 percent since the 2010 IPO.

In 2012 Oasis produced 22,500 BOE per day, more than doubling its 2011 output and quadrupling  production since 2010. Average daily production in Q1 2013 was 30,153 barrels of oil equivalent per day, a 71% increase over the Q1 2012. Management expects 2013 production to be 30,000 to 34,000 BOE per day. The company’s proved reserves at the end of 2012 were 143 million BOE, up from 79 million BOE at the end of 2011.

Oasis has an Enterprise Value/EBITDA of 7.9. Shares have appreciated by 71 percent in the past 12 months, and are currently above our Buy target. OAS is a Buy in our Aggressive Portfolio on dips below $38.

Colorado’s Denver Julesburg (DJ) basin is in an early state of development relative to the Bakken and Eagle Ford. Still, since 2008 oil production in Colorado has risen by an impressive 63 percent to a 50-year high.

Noble Energy (NYSE: NBL) was profiled in depth in the last issue of The Energy Strategist. The company is a major players in the DJ basin, with 750,000 net acres under lease at the end of 2012. Noble’s largest onshore field is the Wattenberg field in the DJ Basin, which represents a majority of its onshore US production, though Noble has also hedged its bets with lucrative finds of natural gas in the eastern Mediterranean and oil off the coast of West Africa. The company will be another major beneficiary from higher crude prices, and we’re still waiting to buy its shares cheaper than the current record high.

Pipelines and Railroads

The current prospects for both pipelines and railroads will be reviewed in an upcoming issue of The Energy Strategist. Generally speaking, a sustained collapse in the Brent-WTI differential is good for the pipeline companies and bad for the railroads. It generally costs $5-$10/bbl more to ship oil from the Bakken by rail, for instance, than to ship it by pipeline. When Bakken crude is trading at a $15/bbl discount to coastal crudes, railroads can present some attractive options for shipping cross-country. With the discount at $5/bbl or lower, pipelines gain the upper hand.

Rail shipping is also likely to be hampered by the tragic accident last weekend in Quebec. The death toll now stands at 15, with 60 people still missing from the derailment and fire of the Montreal, Maine & Atlantic Railway train carrying 72 cars filled with crude oil. Such a horrific incident is already shining a spotlight on the practice of shipping crude oil by rail, and while the practice will certainly continue, I fully expect that the industry will see new rules and regulations in response to this tragedy.

Another factor that will shape the the rail versus pipeline competition is whether the current action in the Brent-WTI differential is temporary, or whether it is in the process of reverting to historical norms (which would favor pipelines). Based on the fact that inventories in Cushing, Oklahoma are still near record highs, I believe it likely that the differential will once more widen.

It will likely be 2014 before sufficient pipeline capacity is available to significantly alleviate Cushing’s high inventories. So while I still expect the 2013 Brent-WTI differential to be lower than the 2012 differential, I don’t believe it will remain where it is. If the differential begins to grow once more, expect railroads to regain some ground alongside refiners.