Oil is again climbing toward $100 a barrel and consumers are paying more than ever at the pump. Even natural gas prices have climbed off the mat, besting $4 per million British Thermal units on the New York Mercantile Exchange this week for the first time since mid-2011.
Energy stocks, however, have been anything but sure winners of late. The NYSE Arca Oil Index—comprised of the largest and strongest producers—is up almost 20 percent from the November 2011 lows. But the index is basically flat since January and still below early 2011 levels.
Smaller producers have faced an even tougher road. So have Canadians, and many of the new generation of producer trusts minted in a wave of late 2011 and early 2012 initial public offerings have slid below launch prices and sell for a fraction of last year’s highs.
Why the divergence? It boils down to three words that also apply not coincidentally to real estate: location, location and location.
In the long term, demand for oil and gas ensures all economic supplies will get to market. Near term, however, some of the most prolific energy reserves in North America are limited geographically. There’s inadequate transport, processing and storage to get the oil and gas produced to market, or at least not as cheaply as energy reserves located elsewhere.
Some of North America’s oil and gas fields have produced for decades. As a result, there are roads, pipelines and other facilities in place to get it to market. Over the past few years, new technologies and processing methods have revitalized many of these fields, such as the Permian Basin in west Texas and eastern New Mexico. And as a result, energy midstream companies have been able to expand the existing infrastructure to meet the new shipping needs.
Other areas, however, are relatively new to the game. That includes the prolific oil reserves in the Bakken shale, as well as other shale-rich areas such as Marcellus in Appalachia. The more energy production has grown there, the greater the need for pipelines and processing to get it to market. But despite billions already spent, what’s been built is still lagging behind what’s being produced.
The result is surging energy production must be transported by alternative means, such as via trucks or rail. Until recently, oil by rail was just an experiment. Today, more crude moves by rail than by pipeline from North Dakota in the heart of the Bakken shale. And major railroads are building for much greater growth ahead.
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Rail, however, is ultimately more expensive than pipelines. In recent years, there’s also been a surge of accidents involving spills despite companies’ best efforts, which may pose limitations on its use in the future. Finally, even with more cars transporting fuel than ever before, there’s still a shortage of capacity for moving product from shale rich regions. The more production ramps out, the more acute it becomes.
The upshot is there are huge pools of oil reserves and production in certain areas with a real problem getting economically to market, mainly the refinery belt along the Gulf Coast. That means glut conditions that in turn mean prices are lower, often much lower than the world price.
The persistent difference between the price of the North American benchmark price of oil—West Texas Intermediate Crude (WTI)—and the global Brent price has been largely due to a shortage of pipelines to ship oil from the Cushing, Oklahoma hub to the Gulf. That gap narrowed to just $12.48 a barrel this week, the smallest in nine months and well below the $20 plus typical of recent years.
That’s largely thanks to recent construction of new pipeline capacity, including the reversal of the Seaway pipeline owned by Enterprise Products Partners LP (NYSE: EPD) and Enbridge Inc (TSX: ENB, NYSE: ENB) to carry oil to the Gulf. But it’s still a quite large gap, and the difference has a real impact on profits of companies who sell at the WTI price.
Differentials with the Brent price are far larger in other regions, however. For example, Western Canada Select—the benchmark price for Canadian heavy crude from Alberta—this week sold for $14.35 per barrel less than WTI, or nearly $27 a barrel less than the world price. And the differentials have been far worse earlier this year.
Consequently, some North American oil producers are selling their energy at very good prices now. Their profits are in an uptrend. Others, however, aren’t getting what they thought they would for their energy. They’ve either got to solve the problem of getting it to market economically, or else adjust to lower cash flow, reduced production plans and possibly lower dividends. The impact of wide price differentials is particularly acute for smaller companies, which lack the resources to ride out the weakness.
It works much the same way with North American natural gas. There appears to be plenty of room to boost production. But at this point, there’s no way to sell at anything approaching global prices, given the lack of export infrastructure for liquefied natural gas. What’s produced here must be consumed here, and the result is even after recent gains, gas sells for a fraction of what it does in Europe and Asia.
Again, there’s considerable ongoing construction of LNG export capacity in Canada, and a number of projects await permitting in the US. Sooner or later, this gas will be available to be sold elsewhere. For now, however, the result is a supply glut, and low prices for the foreseeable future.
The natural gas patch’s response to prices has been to steadily scale back on output. North American companies have largely ceased making big capital outlays on gas reserves and production, including those heavily weighted toward gas. And many companies have throttled back on existing output as well. This week, gas rigs in service in the US dropped to a 14-year low, and less than a quarter of its September 2008 peak.
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Now we’re seeing a similar trend for oil producers in some of the areas most affected by pricing differentials, i.e. furthest away from getting their product to where it can be sold at closer to global prices. The result is reduced results for these companies as they retrench to a lower price environment not reflected in the headlines.
It’s also further unsettled an already highly uncertain outlook for energy services companies, which provide drilling equipment and services to producers. We’ve even seen at least one major pipeline project shelved—ONEOK Partners’ Bakken Express—due to an inability to lock in producers to long-term contracts.
Winners: Waiting it Out
For the companies that can stay consistently profitable in this environment, the current difficulties will be fleeting as needed infrastructure is developed. In fact, they spell opportunity to grab valuable assets on the cheap from distressed players. Chevron Corp’s (NYSE: CVX) purchase of a half interest in the Kitimat LNG export project and related gas assets, for example, will provide a strong boost to production in future years.
Conversely, at least one of the companies Chevron bought out—Encana (TSX: ECA, NYSE: ECA)—is struggling in the low gas price environment. Staying in a multi-billion dollar project not likely to produce revenue for several years was no longer tenable for it. Many Canadian tar sands projects face similar economics, which is why so many have attracted deep pocketed and patient partners to keep them going.
The key is size, reach and financial strength. Those who have it are likely to use the current environment to grow faster down the road. Those that don’t have no choice but to adapt until conditions improve.
That’s about the best possible argument to stick with large established players in North American energy, and limit exposure to companies that don’t have a clear path to profitability in the face of pricing differentials.
If shale reserves of oil and gas are anything close to current estimates, US and Canadian companies will enjoy many years of prosperity as production booms. Getting from here to there, however, means being selective about what you own.
What should you do if you own an underperforming energy producer? First, get a handle on its cash flow. If there’s a dividend, it’s important to know how much of the company’s cash flow it consumes, and what’s left over for development.
If a company is consistently spending more cash on dividends and to grow/maintain production than it’s taking in, it will have to borrow or else issue equity to make up the difference. Since the latter may not be an option in this market, the more likely outcome is rising debt, the single biggest cause for energy producer dividend cuts over the past 12 months.
The good news is if you own one of the energy trusts like Sandridge Permian Basin Trust (NYSE: PER), the distribution always follows the cash flow. The amount can fluctuate depending on selling price for energy produced and output of wells it collects royalties on. But debt will never be a ticking time bomb, ready to blow your dividend sky high.
By Roger Conrad at Investing Daily