Daily Energy Blog

The promise of vast quantities of shale gas at low and stable prices is sparking a U.S. industrial revival no one could have envisioned only a few years ago. Most of the big-dollar industrial expansion projects planned for later this decade are chemical facilities and gas-to-liquids (GTL) plants; many of the rest are steel mills and other energy-intensive industrial facilities. If all—or even most—of these projects become a reality over the next five to 10 years, gas producers in the big shale plays would benefit from sharply higher demand and  the likelihood of higher prices as well. But how many industrial projects will actually be built? Will the forecasted industrial boom turn out to be more of a boomlet?  That could happen if several factors converge, like the approval of a few more LNG export terminals, environmental regulations that result in big growth in gas fired generation, and higher natural gas exports to Mexico.  Any combination of these factors could result in significant upward pressure on domestic gas prices. In this two-part series we explore the potential for a shale-driven industrial revival.

With natural gas prices for CME NYMEX Henry Hub futures averaging $3.69/MMBtu so far this year, you might think that the internal rate of return (IRR) for dry natural gas wells in the Haynesville would be under water.  But in fact, wells are still being drilled with IRRs in the low teens.  Granted these wells don’t look nearly as good as liquids plays in other shale basins, but the wells are profitable.  How could this be when the cost of a typical deep, multistage horizontal well in the Haynesville can run $9 million? Today we take you through the math in our production economics model and provide a downloadable spreadsheet.

Oil and gas shale production economics are creating an era of low cost energy in the US. But how do you decide if drilling one well is any more profitable than drilling another well next door or in a different basin? Just like with any other investment opportunity you compare net present values (NPV) and internal rates of return IRR). Today we continue our rundown of shale production financial return calculations with a review of variable production costs and NPV.

The Rockies Express pipeline (REX) will soon reverse its direction of flow.  Surely there is no more dramatic indication of the huge shifts in physical natural gas movements surging across North America. REX will be moving gas westward - out of the Marcellus/Utica plays into Midwest markets. Gas from the Rockies will go somewhere else. That’s certainly a good thing for Appalachian producers, who are facing (irony of ironies) exactly the same kind of pipeline capacity constraints that Rockies producers were dealing with eight years ago.  What can Marcellus/Utica producers learn from the Rockies experience?  What will the REX reversal do for Marcellus/Utica take-away capacity?  Will Rockies gas get back to where it once belonged?  We will explore these questions in this blog series addressing the REX reversal and implications for Marcellus/Utica producers.

The shale gas revolution has transformed the economics of oil and gas production in the U.S. and  its effects have been far reaching ,including reduced dependence on imported oil and gas  supplies and strengthening domestic manufacturing through lower energy costs. Much of the credit for the technological innovation that allowed this revolution to take place is owed to the late George Mitchell (1919 – 2013) and the members of the Mitchell Energy shale gas team who persevered with the technology. Today we begin a series describing the technology and economics behind the shale drilling boom.

Alberta has vast reserves of natural gas, and for years the gas produced there found ready, steady markets in Ontario, Quebec and the U.S. Midwest, Northeast and West. Recently, the traditional buyers of Alberta gas have been turning to other suppliers and an increasing share of the province’s production is stranded in Western Canada. This has resulted in sharply higher gas inventories in Alberta, lower prices for the province’s gas, and high discounts relative to Henry Hub, LA prices at Alberta’s gas hub, AECO. Today we examine the factors behind this quandary.

Natural gas from the Deep Panuke field off the coast of Nova Scotia could have gained a strong foothold in New England during the past few years—if the gas had started flowing in 2010, as had been the plan. New England, with its shift to gas-fired power generation and its wintertime heating needs, surely has needed the gas; it still does. Today, with the first Deep Panuke gas finally expected to come ashore in the next few weeks, we ask, can the new gas from Nova Scotia push its way into New England, or will the coming influx of Marcellus gas into the six-state region push Deep Panuke gas back across the border?