THE shale gas billowing out of American soil is a source of concern as well as cheap energy. Environmentalists worry that fracking, the technique for dislodging gas from shale beds, may pollute the air and local water supplies. The glut of natural gas has a less likely set of victims, too. Instead of banking handsome profits, many of the oil and gas firms that drill for shale gas are suffering from the boom.

Abundant supplies and slow growth in demand have sent gas prices crashing. In 2008 shale gas fetched $12 per million BTU (British thermal units) at Henry Hub, a crossroads of pipelines in Louisiana that serves as the main pricing point for the gas in America. Since then the frackers have been hard at work. From next to nothing shale now provides a quarter of supplies. The rapid rush of gas onto the market has sent prices tumbling (see chart). After falling to below $2 per mBTU in early 2012, prices have now nudged back to $3.40. But for many drillers this is still not enough. Most gas wells require $4 or more to cover costs. Share prices have tumbled for firms such as Chesapeake Energy, Devon Energy and Southwestern Energy. Asset sales to help pay debts racked up by drilling wells have become the norm—on February 25th Chesapeake announced the sale of a stake in land containing wells as part of its efforts to raise $7 billion this year. The pain looks likely to persist. Analysts reckon that gas has a “sweet spot”, where drillers can make money while consumers still feel little pain, of around $5-6 per mBTU. But the economics of American shale beds means getting there will take time. To cork the flow firms have shut down some existing wells and stopped investment in new ones. But some leases with the owners of land that sits atop reserves dictate that gas (and royalties) must flow regardless of prices. Intensive drilling in 2010 and 2011 has left a huge stock of wells that have been paid for but are yet to be hooked up to local pipelines. Some producers have also contracted to deliver gas at higher prices, which keeps the stuff flowing. A quirk of geology is also preventing prices from rising faster. Shale beds can be “dry” or “wet”. As well as gas, the wet wells produce natural-gas liquids (NGLs) such as ethane, butane and propane. These hydrocarbons are valuable for making plastic in petrochemicals plants or for industrial and domestic uses such as firing industrial heaters and barbecues. NGL prices are linked to that of crude oil, the price of which is set globally (unlike gas) and is high. A healthy flow of NGLs will cover the cost of wells; the gas, a free by-product, hits the market whatever its price.

Some drilling rigs have been shunted from “dry” shales to “wet” ones, boosting supplies of this “free” gas. (The rush to liquid-rich shales has also led to a glut of NGLs, so their prices are falling: this will eventually mean less gas and higher prices.) Other rigs have been trucked to shale-oil beds such as the Eagleford in Texas and the Bakken in North Dakota, which also spew out “free” gas. In the Bakken much of it is wastefully flared (ie, burned). “Green completion” standards for wells due to take effect in the next two years will ensure that the gas will be collected and sold, potentially slowing price increases.

Shale gas is still a relatively young industry. Opportunities for efficiency gains and cost-cutting abound. That makes lower prices more tolerable for producers. Energy giants such as ExxonMobil, Shell and Chevron are in for the long haul and have deep enough pockets to put up with low prices for a while. And differences in infrastructure can affect local markets so that prices may deviate from the Henry Hub benchmark.

Statoil, Norway’s national oil company, bought a pipeline connecting the Marcellus shale in Pennsylvania to Toronto in Canada, where gas is around $1 per mBTU costlier. The company is building one to Manhattan for the same reason.

Exporting liquefied natural gas (LNG) would be another way to deal with the gas glut. Gas markets are regional. Outside America, prices are typically much higher. Spot prices in Asia can reach $20. Moving American gas to Asia would therefore be lucrative, and it is perfectly possible.

America’s Gulf coast is lined with plants to turn imported LNG into gas. Built back in the days when people thought that America would need to rely on imports, they are now idle. At a cost, they could be converted into plants that turn American gas into LNG for export.

One of them, Sabine Pass in Louisiana, has an export licence and could start sending gas abroad by 2015. Sixteen more have applied for licences. But gas-consuming American businesses object. In the hope of keeping domestic gas prices ultra-low, they are lobbying the government to block exports. The government, reluctant to anger both Greenpeace and Dow Chemical, is dragging its feet. Prices are sure to rise eventually, but not before producers suffer more pain from the boom they created.