The production costs of shale gas have laden the extractive sector with heavy debt, amid falling prices
ExxonMobil chief Rex Tillerson wasn’t exaggerating in June 2012 when he said “we are all losing our shirts” on US natural gas. Today, the gas glut resulting from over-supply has left shale gas investors saddled with debt and eager to export US reserves in a bid to stem the flow of red on their balance sheets.
The very nature of shale gas formations – variable geologies spread over a large area, in which the gas resource is diffuse and difficult to produce – means operators must continually sink new wells in order to sustain output. This is an incredibly costly exercise, particularly when gas prices are rock bottom.
The reality is that generally only a core 10-15% of a shale formation’s gas (the “sweet spot”) is commercially viable. The poor economics of shale gas are compounded by high decline rates in shale gas wells, which pay out half their total lifetime production in the first year.
As Houston-based equity options trader Richard Finger notes, when you add mineral royalties, taxes, operational expenses and gas preparation costs onto the average well’s $10m price tag, at wholesale gas prices below $3 per thousand cubic feet, the well operates at a loss. And that assumes average production of 6bn cubic feet per well. In January 2013, gas prices continued to hover in the $3 range.
“Right now, the price is absolutely not commercially viable,” says energy analyst Arthur Berman, adding that the breakeven price is more like $6/mcf. He says the only way shale gas will be viable is if technologies advance sufficiently that operators can accurately identify the sweet spots in reserves, if well-completion costs erode, or if gas prices rise significantly.
In September 2012, troubled shale gas high roller Chesapeake Energy divested the majority of its west Texas shale assets at a discount to cash-rich oil majors Chevron and Shell. Exxon meanwhile has struggled with its 2010 $41bn acquisition of fellow energy producer XTO.
The export option
However, with liquefied natural gas (LNG) cargoes currently selling in Asia for four times the US benchmark gas price, operators are vying for export licences. If the US department of energy grants them, the country could export roughly 30bn cubic feet of gas per day.
Industry lobbyists the Marcellus Shale Coalition and the American Petroleum Institute are leaning on the Department of Energy to ramp up LNG exports. In January, both Marcellus Shale Coalition chief executive Kathryn Klaber and API chief economist John Felmy urged the government to approve pending applications for natural gas exports promptly.
Even so, Berman downplays the export option as a “fallacy”. He says proponents of LNG exports have “ignored the cost and time it takes to build the liquefaction facilities, have assumed the world market is static, and have failed to account for competition from Australia and Papua New Guinea” – which have considerable resource and geographical advantages.
He also warns of “a negative impact on US companies and consumers”. Dow Chemical, which has benefited enormously from the shale boom in terms of investment in chemicals and manufacturing, is already leading a new coalition, America’s Energy Advantage, to campaign against LNG exports.
So the future for shale gas is not clear, and it is perhaps not the magic energy answer many were hoping it would be.