Natural Gas Bear Market Will End But Not All Players Will Survive
By: Roger Conrad
- How Expansion Into Hawaii Will Impact the Valuation Of Dunkin’ Brands?
- ArcelorMittal’s Q1 2016 Earnings Preview: Cost Reduction Initiatives To Offset Impact Of Competition From Imported Steels On Earnings
- Anadarko Reports Depressed 1Q’16 Earnings As The Commodity Downturn Persists
- By What Percentage Did Alphabet’s Revenue And EBITDA Increase In The Last Five Years?
- Why Is Diageo Bullish On The African Beer Market?
- How Has Under Armour’s Revenue And Gross Profit Composition Changed In The Last 5 Years?
North American natural gas currently sells for half its five-year average price on the near-term New York Mercantile Exchange futures contract.
And that’s after a rally the past two weeks from a low point of just USD1.90 per million British thermal units, reached Apr. 19.
Gas is still more than 20 percent lower than where it began 2012 and one-third less than the trading range it held six months ago.
And it’s more than 80 percent off the high it hit in mid-2008.
The fact that unprecedented production of natural gas in North America is pushing prices lower is hardly news. The technological advance known as hydraulic fracturing has opened up whole new areas for gas and oil development.
Hydrocarbon reserves that were previously inaccessible or prohibitively expensive to get at are now among the cheapest sources of energy anywhere.
The result is that natural gas production has hit all-time highs in North America. This, combined with an extremely mild winter, has pushed inventories in storage 50 percent above their five-year average to all-time highs for the traditional spring “refill” season. Winter-summer gas price spreads are at all-time lows and barely cover the cost of storing the gas.
Oil and natural gas liquids (NGLs) such as ethane, butane and propane–which are found with gas in many areas–can be easily refined and exported from North America. There are supply bottlenecks, such as the link between Oklahoma’s Cushing hub and Gulf Coast refineries and the lack of adequate shipping capacity out of shale-rich areas like the Marcellus in Appalachia. But enough product can leave the continent for prices to mirror global demand.
Consequently, the massive ramp-up in production of oil and NGLs the past few years hasn’t triggered a corresponding price decline, as it did with natural gas. Rather, liquids are basically following the ups and downs of global oil prices, mostly ups lately with the exception of weather-battered propane.
And producers continue ramp up output of NGLs, with the liquids-rich Marcellus Shale basically doubling gas production in 2011. Ditto the Eagle Ford Shale region of Texas, where some gas wells are as much as 70 percent liquids.
In stark contrast, the unprecedented new supplies of “dry” natural gas currently can’t be exported outside North America. The reason is all of the liquefied natural gas facilities were built when gas prices were pushing USD10 per million British thermal units in the middle of the last decade.
All are consequently geared for imports, for which there is absolutely zero demand.
Several companies–including the consortium led by EnCana Corp (TSX: ECA, NYSE: ECA) to build a facility at the Kitimat site in British Columbia–are planning to build liquefied natural gas (LNG) export facilities. When they do gas will be exported from North America, and prices will likely begin to mirror global demand, as prices for oil and NGLs do now.
Chilling gas to liquefy it is a hugely complicated and expensive process. It’s likely to be late decade before there is any meaningful capacity for export. And until then gas prices in the North America will be set by supply and demand in the US and Canada alone.
To be sure, low gas prices have set off their own dynamic. Already, we’re seeing shut-ins of wells in areas where gas is “driest,” i.e. contains the least liquids. Weather muted the impact of the ongoing switch of industrial companies and power generators to natural gas.
But, as I stated in Coal: What Is It Good For?, the trend has definitely accelerated, particularly in electricity, where companies on both sides of the border are shutting older coal plants and stepping on the gas.
Coal-fired generation, for example, has fallen from 51 percent of the US power supply in 2002 to 44 percent now, even as gas has doubled its share to 20 percent. Coal fell to just 39 percent in December 2011. And, despite aggressive subsidies for renewable energy, the vast majority of new power-generating capacity under construction is now gas.
Sooner or later every commodity cycle turns. The greatest bull markets always fade as higher prices spur development of new supplies, conservation and switching to alternatives. Similarly, the biggest bear markets always eventually turn, as lower prices stimulate demand, spur switching to the fallen commodity and dry up excess supply by discouraging higher cost production.
In other words, the natural gas bear market will eventually end. But it’s almost certainly going to take more time, and not all of the current players are going to make it out. After all, everyone makes money at USD6 gas and most do at USD4 gas. But very few do so at USD2, and only a tiny handful can at USD1.
Moreover, the full fallout of falling gas has almost certainly yet to be felt across the broad range of sectors affected, which includes power generators and pipeline operators as well as propane distributors and others.
Now more than ever it’s critical for investors to know where their companies are vulnerable to natural gas’ crash and how they might benefit.
For more on profiting from rising shale gas production, check out my colleague, Elliott Gue’s free report, Profits from the Shale Gas Revolution.