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The hydraulic fracturing boom has unlocked massive new supplies of natural gas, and in the process has driven gas prices to rock-bottom levels. But signs of building gas demand suggest that a long-term price recovery is in the works.
Since 2010, the benchmark price for natural gas futures contracts has mostly held below $5 per million British thermal units (MMBtu). Frequently, the price has dipped as low as $2 per MMBtu, as drillers from Pennsylvania to Texas have raised output from previously uneconomical gas deposits buried in shale and other hard-to-drill rock.
The flood of new supplies has been dramatic. U.S. gas production rose more than 32% from January 2010 to January 2015, vaulting the U.S. into the top spot among gas producers worldwide. That’s good news for gas users, since more supply has helped push prices down, but bad news for gas producers, for the same reason. The number of rigs actively drilling for natural gas has plummeted, from more than 800 in January 2010 to a bit more than 200 today. And yet output continues to soar: The Department of Energy figures supply will rise a healthy 6% this year from 2014’s already-high level.
It might be tempting to assume that gas prices will remain low for the foreseeable future. However, demand is also on the rise, and it figures to ramp up further in coming years as the U.S. burns more gas for everything from generating electricity to fueling trucks and ships.
Take power plants. In 2010, the share of electricity generated by burning natural gas was a modest 24%, versus nearly 45% for coal. But because of tougher environmental regulations that are forcing many coal plants to close, the DOE expects gas to generate 31% of the nation’s power in 2015, versus 36% for coal. (The total amount of power generated this year will likely come in right around 2010’s level because of stagnant growth in demand for electric power.)
With even more coal plants slated to be retired over the next few years, utilities will increasingly call on gas to help take up the slack. Renewables are still in their infancy, and new nuclear plants are proving extremely expensive to build, meaning that neither of those sources can easily replace the amount of coal-fired capacity being lost. The DOE estimates that the coal plants closing this year alone accounted for 1.6% of all power generated in the U.S. last year. That’s a lot of megawatt-hours to replace.
Demand for gas is also growing from a surprising source: Fleets of trucks switching from costly diesel fuel to cheaper compressed or liquefied natural gas to save on fuel costs. Though still a tiny slice of total demand, gas consumed by vehicles has risen more than 17% over the past five years. Much of that growth has come from an expanding fleet of gas-powered garbage trucks and other trucks that follow relatively short, predictable routes served by dedicated natural gas fueling stations.
The recent slide in diesel prices has made switching to new gas-powered trucks less compelling. Clean Energy Fuels, an installer of CNG and LNG fueling stations that has benefited from the recent gas-to-diesel shift, expects a bit of a slowdown in 2015, says spokesman Gary Foster. But the company continues to open new fueling stations and believes truck fleets will gravitate to gas in the long run.
Foster says that even with diesel prices down from last year, gas still costs less than the energy-equivalent amount of diesel. As oil prices rebound, that advantage should widen again. Plus, he says, builders of truck engines are starting to introduce more models that run on LNG, which should hasten adoption in a few years.
And note that even ship owners are starting to take a harder look at gas as an alternative to cheap but polluting bunker fuel. One company, TOTE, is commissioning the world’s first oceangoing containerships powered by LNG, the first of which is scheduled to enter service late this year. TOTE CEO Anthony Chiarello says the firm is moving to clean-burning LNG to meet tightening rules on maritime emissions that govern ships traveling within 200 miles of the coast of the U.S. and other participating countries. At $350 million for two new LNG-powered vessels, it’s an expensive solution, but Chiarello predicts that other shipping lines will follow suit in five to 10 years.
Exports Ramping Up
The U.S. has long been a net importer of natural gas. But that’s about to change, once a handful of LNG export terminals begin liquefying some of America’s newfound gas riches and loading it onto tanker ships bound for Europe and Asia. The first export terminal, Cheniere Energy’s Sabine Pass facility in Louisiana, is slated to begin shipments as soon as the end of the year. Four more export terminals — from Cheniere, Dominion, Freeport LNG and Sempra Energy — are also in the works and scheduled to come on line by 2019.
Combined, those terminals will be able to export about 9 billion cubic feet of gas per day when they’re fully operational. That represents a bit less than one-eighth of all the gas consumed in the U.S. in February (the latest month for which output data is available). Gas exports via pipeline to Mexico also figure to climb.
So where do gas prices go from here? After briefly surpassing $6 per MMBtu during the “polar vortex” cold snaps of last year, gas has gradually trended down, to about $3 per MMBtu today. Amazingly, even the brutal cold that sent gas demand in the Northeast to all-time records this past winter couldn’t nudge prices higher.
Predicting short-term gas price movements is notoriously difficult, says Stephen Schork, who covers energy markets as editor of the Schork Report. “Traders have had their faces ripped off” guessing wrong on which way the market will move next, he says. Anything from an unusually cool spring to a freak summer heat wave can roil prices.
But in the longer run, gas prices look poised to trend higher. Demand not only will keep rising, but the rise will accelerate as the U.S. simultaneously generates more power from gas and exports more to overseas markets. Prices will stay volatile, but we see them heading toward an average of closer to $4 per MMBtu than the $2-$3 level that has prevailed in recent years. Bouts of prolonged summer heat or winter cold could cause higher spikes.
Gas consumers should figure on their bills rising over the next couple of years and act accordingly. That might mean locking into a long-term supply contract if the price on offer seems right; investing in insulation to reduce winter heating needs; or replacing old, inefficient gas appliances.
Higher gas prices bode well for gas producers. The biggest suppliers, such as Chesapeake Energy, Anadarko, Devon Energy and Southwestern Energy, figure to reap the biggest profits when prices do turn higher.
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Oil prices have rebounded from their winter lows. But the oil industry isn’t out of the woods yet.
Since St. Patrick’s Day, when West Texas Intermediate — the U.S. crude oil benchmark — bottomed out at $43.46 per barrel, oil has been on a tear. At today’s price of $60 per barrel, WTI has rebounded by more than 30%.
A few key factors have fueled that rise. First, the amount of crude held in storage is no longer soaring the way it was this past winter, when investors fretted that storage depots would run out of physical space to hold all of the oil coming out of shale fields from Texas to North Dakota. In recent weeks, the Department of Energy’s weekly data has shown only small increases in stockpiles.
Oil is no longer piling up in storage so quickly because refineries are buying more and turning it into motor fuel. Demand for gasoline has been strong this spring, thanks to continued modest hiring gains that are putting more folks behind the wheel as they commute to new jobs. Plus, cheaper gasoline is likely spurring more travel. As a result, the Department of Transportation reports that Americans are driving more miles than ever before. (See page 2 of the DOT report for historical data.)
And, finally, U.S. oil output has hit a plateau. After growing sharply last year and during the early months of 2015, daily output is now holding fairly steady at a bit less than 9.4 million barrels. Chalk it up to the huge reduction in drilling activity prompted by the sharp drop in oil prices that started last year. The number of rigs actively drilling for oil is down more than half from last autumn, and will likely keep falling. That, in turn, means U.S. oil output might start falling fairly soon.
All of that is bullish for prices. But nobody in the oil industry is breathing a sigh of relief yet.
First of all, another price drop can’t be ruled out. Stephen Schork, editor of the Schork Report, a daily publication that analyzes the fundamentals of energy markets for professional traders, thinks the recent price rebound in oil is overdone. Refineries are buying lots of crude now to take advantage of large profit margins on refined fuel, a buying spree that he believes won’t continue. That could spell another “leg down” for crude prices sometime before summer arrives.
Companies in the oil patch are all too aware of that possibility, and they are investing accordingly, paring drilling budgets and looking everywhere for cost savings. One Texas-based energy consultant, who requested anonymity so he could speak freely, says that “caution is the MO” right now as drillers focus on their most promising oil fields and cut spending everywhere else.
That means targeting areas with lower drilling costs, such as the Eagle Ford Shale in Texas, and avoiding higher-cost plays such as North Dakota’s Bakken Shale. (Bakken producers are also handicapped by the lack of pipeline capacity there, which causes North Dakota crude to trade at a significant discount to WTI.)
But even Texas is seeing reduced drilling investment. The Railroad Commission of Texas, which regulates state oil and gas production, reports that it granted fewer than half as many oil drilling permits in the first three months of 2015 than it did during the same period last year. The same story is playing out just about everywhere in oil country. In Louisiana, for instance, drilling activity has fallen to 1970s levels, says Ragan Dickens, director of communications for the Louisiana Oil & Gas Association. The downturn has been especially bad for the many oilfield services companies based in Louisiana that do business in other oil states, he says.
The Upshot for Investors
We look for oil prices to gradually grind higher, with WTI ranging from $60 to $65 per barrel by August and a tad higher in September. But even if that pans out, markets figure to stay volatile, and many firms in the oil industry will remain under pressure.
So where does that leave investors who are trying to size up the oil industry? In the short term, it seems clear that companies that refine or transport crude and petroleum products are in better shape than companies that pump oil out of the ground. Energy expert Schork favors refiners, which are benefiting from relatively affordable oil and the recent run-up in gasoline prices. That makes refiner Phillips 66 a more profitable bet than Conoco, its former parent, he says. If you’re interested in energy master limited partnerships, “you’ve got to stay away” from those that produce oil.
Firms that provide services to oil drillers appear to be especially risky bets in the near term, too. The anonymous Texas energy consultant says he knows of service providers that are slashing their rates below cost, simply to hang on to clients that are demanding big discounts. By contrast, the integrated oil majors that both produce and refine oil are more insulated from such pressures. Firms such as Exxon, Shell and BP are making less on the oil they’re pumping, but their huge refining operations help offset those losses.
Tesla Powers Up the Battery Market
A few weeks ago, we wrote about the growth prospects for the energy storage business. Right on cue, electric car maker Tesla has announced a new line of lithium-ion batteries that it will begin selling to homeowners, commercial customers and utilities this summer.
We’ll reserve judgment on the quality of Tesla’s batteries until customers start testing them, but there’s no question that this is a sign of the energy storage industry’s future. At $3,500 plus installation, Tesla’s battery should be a compelling option for both homeowners and businesses looking to guard against blackouts or store energy generated during the day by rooftop solar panels.
Electricity customers whose utilities charge “time of use” rates that vary during the day could especially benefit from the growing supply of large batteries. Such plans charge higher rates during times of peak demand and lower rates at night or during mild weather. Customers who can charge a large battery when prices are low and then run their homes or businesses with that stored energy during the day when rates are high will be able to shave their electric bills, perhaps substantially.
According to the Department of Energy, in 2013 (the most recent data available) more than 4 million residential customers were covered by time-of-use pricing plans. It’s a near certainty that such pricing will expand in the years ahead as utilities look to manage peak demand for power without building expensive new power plants.